<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(MARK ONE)
Annual Report Under Section 13 or 15(d)
[X] of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 1996 or
Transition Report Pursuant to Section 13 or 15(d)
[ ] of the Securities Act of 1934 for the
Transition Period from______________to____________
COMMISSION FILE NO.: 1-10762
BENTON OIL AND GAS COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE
(State or other jurisdiction of 77-0196707
incorporation or organization) (I.R.S. Employer Identification Number)
1145 EUGENIA PLACE, SUITE 200
CARPINTERIA, CALIFORNIA 93013
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (805) 566-5600
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
Common Stock, $.01 Par Value NASDAQ
Common Stock Purchase Warrants, NASDAQ
$11.00 exercise price
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
----- ------
On March 26, 1997, the aggregate market value of the shares of voting stock of
Registrant held by non-affiliates was approximately $464,337,950 based on a
closing sales price on NASDAQ of $16.375.
As of March 26, 1997, 28,999,716 shares of the Registrant's common stock were
outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's Proxy Statement for the 1997 Annual Meeting of
Stockholders to be filed with the Securities and Exchange Commission, not later
than 120 days after the close of its fiscal year, pursuant to Regulation 14A,
are incorporated by reference into Items, 10, 11, 12, and 13 of Part III of this
annual report.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.[X]
<PAGE> 2
BENTON OIL AND GAS COMPANY
FORM 10-K
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
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Part I
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<S> <C> <C>
Item 1. Business.......................................................3
Item 2. Properties....................................................16
Item 3. Legal Proceedings.............................................16
Item 4. Submission of Matters to a Vote of Security Holders ..........17
Part II
- -------
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters............................18
Item 6. Selected Consolidated Financial Data..........................19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................21
Item 8. Financial Statements and Supplementary Data...................26
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ....................26
Part III
- --------
Item 10. Directors and Executive Officers of the Registrant ...........26
Item 11. Executive Compensation........................................26
Item 12. Security Ownership of Certain Beneficial
Owners and Management......................................26
Item 13. Certain Relationships and Related Transactions ...............26
Part IV
- -------
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K........................................27
Financial Statements.........................................................29
Signatures...................................................................54
</TABLE>
<PAGE> 3
PART I
The Company cautions that any forward-looking statements (as such term is
defined in the Private Securities Litigation Reform Act of 1995) contained in
this report or made by management of the Company involve risks and uncertainties
and are subject to change based on various important factors. The following
factors, among others, in some cases have affected and could cause actual
results and plans for future periods to differ materially from those expressed
or implied in any such forward-looking statements: fluctuations in oil and gas
prices, changes in operating costs, overall economic conditions, political
stability, currency and exchange risks, changes in existing or potential
tariffs, duties or quotas, availability of additional exploration and
development opportunities, availability of sufficient financing, changes in
weather conditions, and ability to hire and train personnel.
ITEM 1. BUSINESS
GENERAL
Benton Oil and Gas Company (the "Company") is an independent energy company
which has been engaged in the development and production of oil and gas
properties since 1989. Although originally active only in the United States, the
Company has developed significant interests in Venezuela and Russia, and has
sold substantially all of its United States oil and gas interests. The Company's
operations are conducted principally through its 80% owned Venezuelan
subsidiary, Benton-Vinccler, C.A. ("Benton-Vinccler"), which operates the South
Monagas Unit in Venezuela, and its 34% owned Russian joint venture, GEOILBENT,
which operates the North Gubkinskoye Field in Siberia, Russia. The Company has
also recently expanded into projects which include significant exploration
components, in Venezuela through its participation in the Delta Centro
exploration block and in the South China Sea through its acquisition of Crestone
Energy Corporation.
As of December 31, 1996, the Company had total assets of $435.7 million, total
estimated proved reserves of 109,620 MBOE, and a standardized measure of
discounted future net cash flow, before income taxes, for total proved reserves
of $537.6 million. For the year ended December 31, 1996 the Company had total
revenues of $165.1 million and net income of $28.3 million.
The Company has been successful in increasing reserves, production, revenues and
earnings during the last three years. From year end 1993 through 1996, estimated
proved reserves increased from 42,785 MBOE to 109,620 MBOE and net production
increased from a total of 519 MBOE in 1993 to 11,144 MBOE in 1996. Over the same
period, fully diluted results per share have increased from a loss of $0.26 per
share in 1993 to income of $0.93 per share for the year ended December 31, 1996.
BUSINESS STRATEGY
The Company's business strategy is to identify and exploit new oil and gas
reserves in under-developed areas while seeking to minimize the associated risk
of such activities. Specifically, the Company endeavors to minimize risk by
employing the following strategies in its business activities: (i) seek new
reserves in areas of low geologic risk; (ii) use proven advanced technology in
both exploration and development to maximize recovery; (iii) establish a local
presence through joint venture partners and the use of local personnel; (iv)
commit capital in a phased manner to limit total commitments at any one time;
and (v) reduce foreign exchange risks through receipt of revenues in U.S.
currency.
SEEK NEW RESERVES IN AREAS OF LOW GEOLOGIC RISK. The Company has had significant
success in identifying under-developed reserves in the U.S. and internationally.
In particular, the Company has notable experience and expertise in seeking and
developing new reserves in countries where perceived potential political and
operating difficulties have sometimes discouraged other energy companies from
competing. As a result, the Company has established operations in Venezuela and
Russia with significant reserves that have been acquired and developed at
relatively low costs. The Company is seeking similar opportunities in other
countries and areas which it believes have high potential.
<PAGE> 4
USE OF PROVEN ADVANCED TECHNOLOGY IN BOTH EXPLORATION AND DEVELOPMENT. The
Company's use of 3-D seismic technology, in which a three dimensional image of
the earth's subsurface is created through the computer interpretation of seismic
data, combined with its experience in designing the seismic surveys and
interpreting and analyzing the resulting data, allow for a more detailed
understanding of the subsurface than do conventional surveys. Such technology
contributes significantly to field appraisal, development and production. The
3-D seismic information, in conjunction with subsurface geologic data from
previously drilled wells, is used by the Company's experienced in-house
technical team to identify previously undetected reserves. The 3-D seismic
information can also be used to guide drilling on a real-time basis, and has
been especially helpful in the horizontal drilling done in Venezuela in order to
take advantage of oil-trapping fault lines.
ESTABLISH A LOCAL PRESENCE THROUGH JOINT VENTURE PARTNERS AND THE USE OF LOCAL
PERSONNEL. The Company has sought to establish a local presence where it does
business through joint venture arrangements with local partners to facilitate
stronger relationships with local government and labor. Moreover, the Company
employs almost exclusively local personnel to run foreign operations both to
take advantage of local knowledge and experience and to minimize cost. These
efforts have created an expertise within Company management in forming effective
foreign partnerships and operating abroad. The Company believes that it has
gained access to new development opportunities as a result of its reputation as
a dependable partner.
COMMIT CAPITAL IN A PHASED MANNER TO LIMIT TOTAL COMMITMENTS AT ANY ONE TIME.
While the Company typically has agreed to a minimum capital expenditure or
development commitment at the outset of new projects, expenditures to fulfill
these commitments are phased over time. In addition, the Company seeks, where
possible, to use internally generated funds for further capital expenditures and
to invest in projects which provide the potential for an early return to the
Company.
REDUCE FOREIGN EXCHANGE RISKS. The Company seeks to reduce foreign currency
exchange risks by providing for the receipt of revenues by the Company in U.S.
dollars while most operating costs are incurred in local currency. Pursuant to
the operating agreement between the Company's Venezuelan subsidiary and the
state oil company, the operating fees earned by the Company are paid directly to
the Company's bank account in the U.S. in U.S. dollars. GEOILBENT receives
revenues from export sales in U.S. dollars paid to its account in Moscow;
domestic sales are paid in roubles under agreements which call for advance or
guaranteed payments. As the Company expands internationally, it will seek to
establish similar arrangements for new operations.
PRINCIPAL AREAS OF ACTIVITY
The following table summarizes the Company's proved reserves, drilling and
production activity, and financial operating data by principal geographic area
at and for each of the years ended December 31:
<TABLE>
VENEZUELA(1) RUSSIA(2) UNITED STATES
----------------------------- -------------------------- --------------------------
(dollars in 000's) 1996 1995 1994 1996 1995 1994 1996 1995 1994
------- ------- ------- -------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
RESERVE INFORMATION:
Proved Reserves (MBOE) 86,076 73,593 60,707 23,544 22,618 17,540 -- 1 2,913
Discounted Future Net Cash
Flow Attributable to
Proved Reserves,
Before Income Taxes $446,854 $286,916 $268,830 $90,705 $85,361 $48,833 -- $16 $18,657
Standardized Measure of
Future Net Cash Flows $323,550 $206,545 $172,703 $73,423 $55,434 $32,398 -- $16 $18,286
DRILLING AND PRODUCTION
ACTIVITY:
Gross Wells Drilled 31 21 11 5 21 9 1 5 5
Average Daily Production 34,557 14,949 6,902 2,091 1,345 806 2,862 1,917 1,561
(BOE)
</TABLE>
<PAGE> 5
<TABLE>
<CAPTION>
VENEZUELA(1) RUSSIA(2) UNITED STATES
----------------------------- -------------------------- -------------------------
(dollars in 000's) 1996 1995 1994 1996 1995 1994 1996 1995 1994
------- ------- ------- -------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FINANCIAL DATA:
Oil and Gas Revenues $136,840 $ 49,174 $ 21,472 $ 9,047 $ 6,016 $ 3,513 $4,675 $ 7,683 $ 7,287
Expenses:
Lease Operating Costs
and 17,669 6,483 3,808 6,263 2,764 2,832 585 1,456 2,891
Production Taxes
Depletion 29,523 11,393 4,998 2,747 1,512 838 1,705 4,188 4,248
--------- -------- --------- ------- -------- -------- -------- ------- --- -----
Total Expenses 47,192 17,876 8,806 9,010 4,276 3,670 2,290 5,644 7,139
--------- --------- --------- ------- -------- -------- -------- ------- ---------
Results of Operations from
Oil and Gas Producing
Activities $ 89,648 $ 31,298 $ 12,666 $ 37 $ 1,740 $ (157) $ 2,385 $ 2,039 $ 148
========= ========= ========= ======= ======== ======== ======== ======= ========
<FN>
(1) Includes 100% of the reserve information, drilling and production activity
and financial data, without deduction for minority interest. All Venezuelan
reserves are attributable to an operating service agreement between
Benton-Vinccler and Lagoven, S.A. under which all mineral rights are owned
by the Government of Venezuela. See Item 1. Business--South Monagas Unit,
Venezuela and --Reserves.
(2) The financial information for Russia includes information for the twelve
months ended December 31, 1994, the nine months ended September 30, 1995
and the twelve months ended September 30, 1996, the end of the fiscal
period for GEOLBENT.
</TABLE>
SOUTH MONAGAS UNIT, VENEZUELA
GENERAL
In July 1992, the Company and Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), a Venezuelan construction and engineering company,
signed a 20-year operating service agreement with Lagoven, S.A. ("Lagoven"), an
affiliate of the national oil company, Petroleos de Venezuela S.A. ("PDVSA"), to
reactivate and further develop the Uracoa, Bombal and Tucupita Fields, which are
a part of the South Monagas Unit (the "Unit"). At that time, the Company was one
of three foreign companies ultimately awarded an operating service agreement to
reactivate existing fields by PDVSA, and was the first U.S. company since 1976
to be granted such an oil field development contract in Venezuela.
The oil and gas operations in the Unit are conducted by Benton-Vinccler, the
Company's 80% owned subsidiary. The remaining 20% of the outstanding capital
stock of Benton-Vinccler is owned by Vinccler. The Company, through its majority
ownership of stock in Benton-Vinccler, makes all operational and corporate
decisions related to Benton-Vinccler, subject to certain super-majority
provisions of Benton-Vinccler's charter documents related to mergers,
consolidations, sales of substantially all of its corporate assets, change of
business and similar major corporate events. Vinccler has an extensive operating
history in Venezuela. It provided the Company with initial financial assistance
and continues to provide ongoing assistance with construction services and
governmental and labor relations.
Under the terms of the operating service agreement, Benton-Vinccler is a
contractor for Lagoven and is responsible for overall operations of the South
Monagas Unit, including all necessary investments to reactivate and develop the
fields comprising the Unit. The Venezuelan government maintains full ownership
of all hydrocarbons in the fields. In addition, Lagoven maintains full ownership
of equipment and capital infrastructure following its installation.
Benton-Vinccler invoices Lagoven each quarter based on Bbls of oil accepted by
Lagoven during the quarter, using quarterly adjusted contract service fees per
Bbl, and receives its payments from Lagoven in U.S. dollars deposited directly
into a U.S. bank account. The operating service agreement provides for
Benton-Vinccler to receive an operating fee for each Bbl of crude oil delivered
and a capital recovery fee for certain of its capital expenditures, provided
that such operating fee and capital recovery fee cannot exceed the maximum total
fee per Bbl set forth in the agreement. The operating fee is subject to periodic
adjustments to reflect changes in the special energy index of the U.S. Consumer
Price Index, and the maximum total fee is subject to periodic adjustments to
reflect changes in the average of certain world crude oil prices. Since
commencement of operations, the adjusted maximum total fee has often been less
than the adjusted operating fee, resulting in no capital recovery fee. The
Company cannot predict the extent to which future maximum total fee adjustments
will provide for capital recovery components in the fees it receives, and has
recorded no income or asset for capital recovery fees other than when received.
<PAGE> 6
Since 1992, when Venezuela signed the initial agreements related to the
reactivation and further development of certain fields, the country has
continued to invite foreign assistance in its oil and gas exploration,
development and production. Management believes that Venezuela continues to
provide potential business opportunities for the Company. See -- Delta Centro
Block, Venezuela.
LOCATION AND GEOLOGY
The Unit is located in the southeastern part of the state of Monagas and the
western part of Delta Amacuro in eastern Venezuela. The Unit is approximately 51
miles long and eight miles wide and consists of 157,843 acres, of which the
fields comprise approximately one-half. At December 31, 1996, proved reserves
attributable to the Company's Venezuelan operations were 86,076 MBOE, which
represented 79% of the Company's proved reserves. Benton-Vinccler is currently
developing the Uracoa and Tucupita Fields, which contain 97% of the Unit's
proved reserves. The associated natural gas which is produced is currently being
reinjected into the field and flared, as no ready market exists for the natural
gas.
DRILLING AND DEVELOPMENT ACTIVITY
Benton-Vinccler has been developing the South Monagas Unit since 1992. During
March 1997 (through March 26), a total of approximately 75 wells produced an
average of approximately 40,000 Bbls of oil per day in the Unit. The following
table sets forth drilling activity and production information for each of the
quarters presented:
<TABLE>
<CAPTION>
WELLS DRILLED AVERAGE DAILY
---------------------------- ---------------------------
VERTICAL HORIZONTAL PRODUCTION FROM FIELD (BBL)
-------- ---------- ---------------------------
<S> <C> <C> <C>
1994:
First Quarter 5 0 3,400
Second Quarter 0 0 6,700
Third Quarter 3 0 7,200
Fourth Quarter 0 3 10,200
1995:
First Quarter 1 1 11,800
Second Quarter 1 2 11,300
Third Quarter 2 2 15,800
Fourth Quarter 1 8 20,800
1996:
First Quarter 3 8 29,600
Second Quarter 4 3 33,700
Third Quarter 2 7 37,700
Fourth Quarter 1 5 40,500
</TABLE>
Benton-Vinccler contracts with third parties for drilling and completion of
wells. Currently, Helmerich & Payne International Drilling Co. is performing
drilling services for Benton-Vinccler under contract. The Company's technical
personnel identify drilling locations, specify the drilling program and
equipment to be used and monitor the drilling activities. To date, 15 previously
drilled wells have been reactivated and 74 new wells have been drilled using
modern drilling and completion techniques that had not previously been utilized
in the Unit, with 73, or 99%, completed and placed on production. Two drilling
rigs are currently working in the Unit. Benton-Vinccler plans to drill
approximately 6 vertical and 19 horizontal wells, 2 injection wells and 3
re-entry wells during 1997, at an anticipated cost to the Company of
approximately $50-60 million.
<PAGE> 7
In December 1993, Benton-Vinccler commenced drilling the first horizontal well.
Since the completion of this well, the Company has successfully integrated
modern technology and modern drilling and completion techniques to improve the
ultimate recovery. The Company has conducted a 3-D seismic survey and
interpreted the seismic data over the Unit. As a horizontal well is drilled,
information regarding formations encountered by the drill bit is transmitted to
the Company. Geologists, engineers and geophysicists at the Company can
determine the location of the drill bit by comparing the information about the
formations being drilled with the 3-D seismic data. The Company then directs the
movement of the drill bit to more accurately direct the well to the expected
reservoir. The Company intends to continue this method of horizontal drilling in
the development of the field.
Once oil is produced, it is transported to production facilities which were
designed in the United States and installed by Benton-Vinccler. These production
facilities are of the type commonly used in heavy oil production in the United
States, but not previously used extensively in Venezuela to process crude oil of
similar gravity or quality. The current production facilities are capable of
processing approximately 45,000 Bbls of oil per day. Benton-Vinccler intends to
expand the capacity of the production facilities in 1997 to a total capacity of
60,000 Bbls of oil per day. The Company anticipates capital expenditures of $18
million during 1997 to complete such expansion.
CUSTOMERS AND MARKET INFORMATION
Oil produced in Venezuela is delivered to Lagoven under the terms of an
operating service agreement for an operating service fee. Benton-Vinccler has
constructed a 25-mile oil pipeline from its oil processing facilities at Uracoa
to Lagoven's storage facility, which is the custody transfer point. The service
agreement specifies that the oil stream may contain no more than 1% base
sediment and water, and quality measurements are conducted both at
Benton-Vinccler's facilities and at Lagoven's storage facility. A continuous
flow measuring unit is installed at Benton-Vinccler's facility, so that quantity
is monitored constantly. Lagoven provides Benton-Vinccler with a daily
acknowledgment regarding the amount of oil accepted the previous day, which is
reconciled to Benton-Vinccler's measurement. At the end of each quarter,
Benton-Vinccler prepares an invoice to Lagoven for that quarter's deliveries.
Lagoven pays the invoice at the end of the second month after the end of the
quarter. Invoice amounts and payments are denominated in U.S. dollars. Payments
are wire transferred into Benton-Vinccler's account in New York.
EMPLOYEES; COMMUNITY RELATIONS
Benton-Vinccler seeks to employ nationals rather than bring expatriates into the
country. Presently, there are seven full time expatriates working with
Benton-Vinccler and 149 local employees. Benton-Vinccler also conducts ongoing
community relations programs, providing medical care, training, equipment and
supplies, and support for local schools, in both states in which the South
Monagas Unit falls.
DELTA CENTRO BLOCK, VENEZUELA
GENERAL
In February 1996, the Company and its bidding partners, Louisiana Land &
Exploration Company ("LL&E") and Norcen Energy Company ("Norcen"), were awarded
the right to explore and develop the Delta Centro Block in Venezuela. The
contract requires a minimum exploration work program consisting of completing a
1,300-square kilometer seismic survey and drilling three wells to depths of
12,000 to 18,000 feet within five years. PDVSA estimates that this minimum
exploration work program will cost $60 million and requires that the Company,
LL&E and Norcen each post a performance surety bond or standby letter of credit
for its pro rata share of the estimated work commitment expenditures. The
Company has a 30% interest in the exploration venture, with LL&E and Norcen each
owning a 35% interest. Under the terms of the operating agreement, which
establishes the management company for the project, LL&E will be the operator of
the field, and therefore the Company will not be able to exercise control of the
operations of the venture. Corporacion Venezolana del Petroleo, S.A. ("CVP"), an
affiliate of the national oil company, has a 35% interest in the management
company, which dilutes the voting power of the partners on a pro rata basis.
<PAGE> 8
If areas within the block are deemed to be commercially viable, then the group
has the right to enter into further agreements with CVP to develop those areas
during the next 20-25 years. CVP would participate in the revenues and costs
with an interest between 1-35%, at CVP's discretion. Any oil and gas produced at
Delta Centro will be sold at market prices and will be subject to the oil and
gas taxation regime in Venezuela and to the terms of a profit sharing agreement
with PDVSA. Under the current oil and gas tax law, a royalty of up to 16.67%
will be paid to the state. Under the contract bid terms, 41% of the pre-tax
income will be shared with PDVSA for the period during which the first $1
billion of revenues is produced; thereafter, the profit sharing amount may
increase to up to 50% according to a formula based on return on assets.
Currently, the statutory income tax rate for oil and gas enterprises is 66.67%.
Royalties and shared profits are currently deductible for tax purposes.
LOCATION AND GEOLOGY
The Delta Centro Block consists of approximately 2,138 square kilometers
(526,000 acres) located in the delta of the Orinoco River in the eastern part of
Venezuela. Although no significant exploratory activity has been conducted on
the block, PDVSA has estimated that the area may contain recoverable reserves of
as much as 820 million Bbls, and may be capable of producing up to 160,000 Bbls
of oil per day. The general area of Venezuela in which the Delta Centro Block is
located is known to be a significant source of hydrocarbons, evidenced by the
recently discovered El Furrial light oil trend to the north and the Orinoco tar
sands to the south. Based on its geological studies of the basins in this area,
the Company's technical staff believes that hydrocarbons have essentially
migrated over time from the deeper Maturin basin area of Venezuela southward
toward the shallower Orinoco tar belt area. If so, then potential trapping
structures and/or faults in the path of the migrating oil would serve as traps
for the migrating oil and have the opportunity to be filled to their spill
points. Delta Centro is directly in line with this migration path, making it an
attractive exploration area. The area is mostly swampy in nature, with terrain
ranging from forest in the north to savannah in the south. The marshlands in the
block are similar to the transition zone areas in the Gulf of Mexico in which
the Company has significant experience in seismic and drilling operations.
DRILLING AND DEVELOPMENT ACTIVITY
The venture has commenced a 3-D seismic survey over the southwestern portion of
the Delta Centro Block at an expected total cost to the Company during 1997 of
approximately $6-7 million. Following the initial interpretation of the seismic
data, the venture intends to drill an initial exploration well during 1998, at a
cost to the Company of approximately $4 million. Subsequent seismic and drilling
programs will be based on the results of the 1997-1998 activity.
NORTH GUBKINSKOYE, RUSSIA
GENERAL
In December 1991, the joint venture agreement forming GEOILBENT among the
Company (34% interest) and two Russian partners, Purneftegasgeologia and
Purneftegas (each having a 33% interest), was registered with the Ministry of
Finance of the USSR. While both partners have undergone certain levels of
privatization since then, at the time Purneftegasgeologia was the official
geological body of the government whose purpose was to explore for oil and gas
in the Purovsky district of Russia and Purneftegas was the official production
agency of the government responsible for oil and gas production in the area. In
November 1993, the agreement was registered with the Russian Agency for
International Cooperation and Development. Although GEOILBENT may only take
action through the unanimous vote of the partners, the Company believes that it
has developed a good relationship with its partners and has not experienced any
disagreement with its partners on major operational matters. Mr. A. E. Benton,
Chief Executive Officer of the Company, serves as chairman of the governing body
of GEOILBENT.
LOCATION AND GEOLOGY
GEOILBENT develops, produces and markets crude oil from the North Gubkinskoye
Field in the West Siberia region of Russia, approximately 2,000 miles northeast
of Moscow. The field, which covers an area approximately 15 miles long and 4
miles wide, has been delineated with over 60 exploratory wells (which tested 26
separate reservoirs) and is surrounded by large proven fields. Before
commencement of GEOILBENT's operations, North Gubkinskoye was one of the largest
oil and gas fields in the region not under commercial production. The field is a
large anticlinal structure with multiple pay sands. The development to date has
focused on the BP 8, 9, 10, 11 and
<PAGE> 9
12 reservoirs. The natural gas which is produced is currently being flared in
accordance with environmental regulations.
DRILLING AND DEVELOPMENT ACTIVITY
GEOILBENT commenced initial operations in the field during the third quarter of
1992 with the construction of a 37-mile oil pipeline and installation of
temporary production facilities. During March 1997 (through March 26),
approximately 43 wells are producing an average of approximately 5,000 Bbls of
oil per day. The following table sets forth drilling activity and production
information for each of the quarters presented:
<TABLE>
<CAPTION>
AVERAGE DAILY
WELLS DRILLED PRODUCTION FROM FIELD
------------- ---------------------
<S> <C> <C>
1994:
First Quarter 1 1,000
Second Quarter 1 2,400
Third Quarter 2 2,200
Fourth Quarter 5 4,900
1995:
First Quarter 1 4,300
Second Quarter 1 5,600
Third Quarter 9 7,800
Fourth Quarter 11 7,900
1996:
First Quarter 4 8,400
Second Quarter 1 7,200
Third Quarter - 7,100
Fourth Quarter - 6,500
</TABLE>
GEOILBENT contracts with third parties for drilling and completion of wells.
Supervised by a joint American and Russian management team, GEOILBENT identifies
drilling locations, then uses Russian drilling rigs, upgraded by certain western
technology and materials to drill and complete a well. To date, 11 previously
drilled wells have been reactivated and 36 wells have been drilled in the field,
with 32, or 89%, completed and placed on production. Four drilling rigs are
currently working on pads in the field, and once all wells on the pad have been
drilled, each such well will be tested for completion. Each well is drilled to
an average depth of approximately 10,000 feet measured depth and 8,000 feet true
depth.
Once oil is produced, it is flowed to production facilities constructed and
owned by GEOILBENT. Oil is then transferred to GEOILBENT's 37-mile pipeline
which transports the oil from the North Gubkinskoye Field south to the main
Russian oil pipeline network.
The current production facilities are operating at or near capacity and would
need to be expanded to accommodate any increased production. Subject to
obtaining financing, GEOILBENT has a 1997 capital expenditure budget of
approximately $57 million, of which $38 million would be used to drill
approximately 49 wells in the North Gubkinskoye Field and $19 million for
construction of production facilities. GEOILBENT has executed a credit agreement
with the European Bank for Reconstruction and Development ("EBRD") for a $55
million facility, which would be non-recourse to the Company, to be used for
development of the North Gubkinskoye Field, including the production facility
expansion. GEOILBENT is currently negotiating with International Moscow Bank for
a parallel $10 million credit agreement. Borrowings under either facility are
subject to certain initial and ongoing precedent conditions, some of which are
beyond the control of GEOILBENT and the Company. If EBRD or other financing is
delayed or ultimately not obtained, minimal capital expenditures are anticipated
and production from the field is expected to experience a natural decline.
<PAGE> 10
CUSTOMERS AND MARKET INFORMATION
GEOILBENT's 37-mile pipeline runs from the field to the main pipeline in the
area where GEOILBENT transfers the oil to Transneft, the state oil pipeline
monopoly, or to rail car facilities for transportation to markets in Finland.
Transneft can transport the oil to the western border of Russia. Under the
regulations in effect when GEOILBENT was formed, its charter documents called
for all oil production to be for export, and all export oil sales have been
handled by trading companies. During 1996, however, regulations regarding access
to pipelines were changed, creating more competition for pipeline capacity.
While most of GEOILBENT's crude sales were made in U.S. dollars to export
purchasers in 1996, certain sales were made to purchasers who could pay in
roubles either in advance or under payment guarantees.
EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS
Having access to the oilfield labor base in West Siberia, GEOILBENT employs
nationals almost exclusively. Presently, there are three full time expatriates
working with GEOILBENT and over 200 local employees. The Company conducts an
ongoing community relations program in Russia, providing medical care, training,
equipment and supplies in towns in which GEOILBENT personnel reside and also for
the nomadic indigenous population which resides in the area of oilfield
operations.
ALTERNATIVES FOR NATURAL GAS RESERVES
The Company and GEOILBENT estimate that substantial recoverable associated gas
and condensate reserves exist in the North Gubkinskoye Field. In addition, there
are substantial non-associated natural gas reserves in the field. Currently,
there exists no ready market for these reserves, and therefore there are no
plans to produce these gas reserves. Associated gas is flared in allowable
amounts under permits with the Ministry of Fuel and Energy. If no market
develops for the gas, then over time GEOILBENT plans to begin reinjecting it
back into the reservoirs. GEOILBENT currently has no rights to develop much of
the significant gas reserves in the field. However, GEOILBENT has entered into
discussions with Gazprom, the state natural gas monopoly, for development and
production of the solution gas, which is estimated by the Company to be 550-600
Bcf. Implementation of such a development plan would include construction of
processing facilities and of a natural gas pipeline from the field area to the
main transmission pipeline. Certain feasibility studies on the gas development
have been completed, and other studies are currently in process and anticipated
to be completed by year end 1997. Further development, subject to approval of
all parties, will depend upon available financing.
OTHER PROPERTIES
Prior to 1996, the Company had successfully pursued acquisition and joint
venture opportunities in the United States as major oil and gas companies
continued to consolidate operations and focus exploration and development
activities outside the United States. Substantially all of the Company's
domestic activities had been located in the Louisiana Gulf Coast at the West
Cote Blanche Bay, Rabbit Island and Belle Isle Fields. The Company entered into
agreements with Texaco, Inc. ("Texaco") and Oryx Energy Company ("Oryx") to
develop the fields by using 3-D seismic technology integrated with subsurface
geologic data from previously drilled wells. In addition, the Company entered
into certain agreements with Tenneco Ventures Corporation ("Tenneco") whereby
Tenneco purchased certain interests in the Company's operations in the three
fields and was given the right to participate as a 50% partner in certain of the
Company's future activities in the Gulf Coast for the next five years.
In March 1995, the Company and its affiliates and Tenneco sold to WRT Energy
Corporation a 43.75% working interest in the shallower depths (above
approximately 10,575 feet) in the West Cote Blanche Bay Field for an aggregate
purchase price of $20 million. Of this aggregate purchase price, the Company
received $14.9 million. In March 1996, the Company sold to Shell Offshore Inc.
("Shell") all of its interests in the West Cote Blanche Bay, Rabbit Island and
Belle Isle Fields effective December 31, 1995, for a purchase price of $35.4
million.
At December 31, 1996, the Company had no proved reserves in the United States.
During 1996, the Company acquired Crestone Energy Corporation ("Crestone"), a
privately held company headquartered in Denver, Colorado, whose principal asset
is an oil and gas petroleum contract with China National Offshore Oil Company
("CNOOC") for an area known as Wan'An Bei, WAB-21. The WAB-21 petroleum contract
<PAGE> 11
covers 6.2 million acres in the South China Sea, with an option for another one
million acres under certain circumstances, and lies within an area which is the
subject of a territorial dispute between the People's Republic of China and
Vietnam. Vietnam has also executed an agreement on a portion of the same
offshore acreage with Conoco, a unit of DuPont Corporation. The territorial
dispute has existed for many years, and there has been limited exploration and
no development activity in the area under dispute. It is uncertain when or how
this dispute will be resolved, and under what terms the various countries and
parties to the agreements may participate in the resolution, although certain
proposed economic solutions currently under discussion would result in the
Company's interest being reduced. The Company, through Crestone, has submitted
plans and budgets to CNOOC for an initial seismic program to survey the area;
however, exploration activities will be subject to resolution of such
territorial dispute. The Company has recorded no reserves attributable to this
petroleum contract.
EVALUATION OF ADDITIONAL OPPORTUNITIES
The Company continues to evaluate and pursue domestic and international
opportunities which fit within its business strategy. The Company is currently
evaluating certain development and/or acquisition opportunities, but it is not
presently known whether, or on what terms, such evaluations will result in
future agreements or acquisitions.
RESERVES
The following table sets forth information regarding estimates of proved
reserves at December 31, 1996 prepared by the Company and audited by Huddleston
& Co., Inc., independent petroleum engineers:
<TABLE>
<CAPTION>
CRUDE OIL AND CONDENSATE (MBBL)
---------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -----
<S> <C> <C> <C>
Venezuela(1) 47,805 38,271 86,076
Russia(2) 3,417 20,127 23,544
------- ------ --------
Total 51,222 58,398 109,620
====== ====== =======
<FN>
(1) Includes 100% of the reserve information, without deduction for minority
interest. All Venezuelan reserves are attributable to an operating service
agreement between Benton-Vinccler and Lagoven, under which all mineral
rights are owned by the Government of Venezuela. See Item 1.
Business--South Monagas Unit, Venezuela.
(2) Although the Company estimates that there are substantial natural gas
reserves in the North Gubkinskoye Field, no natural gas reserves have been
recorded because of a lack of a ready market.
</TABLE>
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and the timing and amount
of development expenditures, including many factors beyond the control of the
producer. The reserve data set forth above only represent estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates of different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimate. Accordingly, reserve estimates are often different
from the quantities of crude oil and natural gas that are ultimately recovered.
The meaningfulness of such estimates is highly dependent upon the accuracy of
the assumptions upon which they were based.
PRODUCTION, PRICES AND LIFTING COST SUMMARY
The following table sets forth by country net production, average sales prices
and average lifting costs of the Company for the years ended December 31, 1996,
1995 and 1994:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER
----------------------------------------
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
VENEZUELA
Net Crude Oil Production (Bbl) 12,647,987 5,456,473 2,519,514
Average Crude Oil Sales Price ($ per Bbl) $10.82 $9.01 $8.52
Average Lifting Costs ($ per Bbl) 1.40 1.19 1.51
</TABLE>
<PAGE> 12
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER
----------------------------------------
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
RUSSIA (1)
Net Crude Oil Production (Bbl) 765,137 490,960 294,364
Average Crude Oil Sales Price ($ per Bbl) $11.82 $12.25 $11.93
Average Lifting Costs ($ per Bbl) 8.19 5.63 9.62
UNITED STATES
Net Production:
Crude oil and condensate (Bbl) 6,589 68,975 225,954
Natural gas (Mcf) 1,523,106 3,784,830 2,061,892
Average Sales Price:
Crude oil and condensate ($ per Bbl) $19.70 $15.79 $14.46
Natural gas ($ per Mcf) 3.04 1.77 1.79
Average Lifting Costs ($ per BOE) 2.25 2.08 5.08
<FN>
(1) The presentation for Russia includes information for the twelve months
ended December 31, 1994, the nine months ended September 30, 1995 and
the twelve months ended September 30, 1996, the end of the fiscal
period for GEOILBENT.
</TABLE>
REGULATION
GENERAL
The Company's operations are affected by political developments and laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and costs.
Oil and gas industry legislation and agency regulation is periodically changed
for a variety of political, economic, environmental and other reasons. Numerous
governmental departments and agencies issue rules and regulations binding on the
oil and gas industry, some of which carry substantial penalties for the failure
to comply. The regulatory burden on the oil and gas industry increases the
Company's cost of doing business.
In the past, the federal government has regulated the prices at which oil and
gas could be sold. Prices of oil and gas sold by the Company are not currently
regulated, and sales may be made at uncontrolled market prices. The Company's
international operations are also subject to political, economic and other
uncertainties including, among others, risks of war, revolution, expropriation,
renegotiation or modification of existing contracts, export and transportation
tariffs, taxation and royalty policies, foreign exchange restrictions,
international monetary fluctuations and other hazards arising out of foreign
government sovereignty over certain areas in which the Company conducts
operations.
VENEZUELA
Venezuela requires environmental and other permits for certain operations
conducted in oil field development, such as site construction, drilling, and
seismic activities. As a contractor to Lagoven, Benton-Vinccler submits capital
and operating budgets to Lagoven for approval. Capital expenditures to comply
with Venezuelan environmental regulations relating to the reinjection of gas in
the field and water disposal are expected to be $12.7 million in 1997 and $8.0
million in 1998, respectively. Benton-Vinccler also submits requests for permits
for drilling, seismic and operating activities to Lagoven, which then obtains
such permits from the Ministry of Energy and Mines and Ministry of Environment,
as required. Benton-Vinccler is also subject to income, municipal and value
added taxes, and must file certain monthly and annual compliance reports to
SENIAT (the national tax administration) and to various municipalities.
RUSSIA
GEOILBENT submits annual production and development plans, which include
information necessary for permits and approvals for its planned drilling,
seismic and operating activities, to local and regional governments and to the
Ministry of Fuel and Energy, Committee of Geology, Ministry of Economy, and
Ministry of Ecology. GEOILBENT
<PAGE> 13
also submits annual production targets and quarterly export nominations for oil
pipeline transportation capacity to the Ministry of Fuel and Energy. GEOILBENT
is subject to customs, value added, and municipal and income taxes. Various
municipalities and regional tax inspectorates are involved in the assessment and
collection of these taxes. GEOILBENT must file operating and financial
compliance reports with several bodies, including the Ministries of Fuel and
Energy, Geology, Committee for Technical Mining Monitoring of the Ministry of
Ecology, and the State Customs Committee.
DRILLING, ACQUISITION AND FINDING COSTS
During the years ended December 31, 1996, 1995 and 1994, the Company spent
approximately $108 million, $74 million and $53 million, respectively, for
acquisitions of leases and producing properties, development and exploratory
drilling, production facilities and additional development activities such as
workovers and recompletions.
The Company has drilled or participated in the drilling of wells as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBE 31,
------------------------------------------------------
1996 1995 1994
----------- ---------------- ---------------
GROSS NET GROSS NET GROSS NET
<S> <C> <C>
WELLS DRILLED:
Exploratory:
Crude oil ......... -- -- 3 1.020 -- --
Natural gas ....... 1 .375 3 .970 2 .875
Dry holes ......... -- --- 1 .375 2 .869
Development:(1)(2)(3)
Crude oil ......... 36 26.500 41 22.680 20 11.860
Natural Gas ....... -- -- 1 .220 1 .435
Dry Holes ......... -- -- 1 .8000 -- --
----- ------ ----- ------- ------ -------
TOTAL ...................... 37 26.875 50 26.065 25 14.039
===== ====== ===== ======= ===== =======
AVERAGE DEPTH OF WELLS FEET) 8,008 7,847 7,266
PRODUCING WELLS (4):
Crude Oil .............. 113 74.300 77 44.701 112 46.796
Natural Gas ............ 0 0 8 2.024 4 .822
<FN>
(1) In addition to the activities set forth in the table, at the West Cote
Blanche Bay Field during the year ended December 31, 1994, the Company
participated in the successful recompletion of 13 gross (4.247 net) oil
wells and one gross (.327 net) gas well. In March 1995, the Company sold
certain of its interests in the field, a result of which was to
substantially eliminate the Company's future participation in recompletion
and redrilling activities and in March 1996, the Company sold the remainder
of its interests in the field. See Item 1. Business -- Other Properties.
(2) In addition to the activities set forth in the table, the Company
participated in the successful recompletion of five gross (4.0 net) oil
wells in Venezuela during the year ended December 31, 1994
(3) In addition to the activities set forth in the table, the Company
participated in the successful reactivation of one gross (.34 net) oil well
in Russia during the year ended December 31, 1995. The Company participated
in the successful reactivation of six gross (2.04 net) oil wells in Russia
during the year ended December 31, 1994.
(4) The information related to producing wells reflects wells the Company has
drilled, wells the Company has participated in drilling and producing wells
the Company has acquired.
</TABLE>
At December 31, 1996 the Company was participating in the drilling of 2 wells in
Venezuela.
All of the Company's drilling activities are conducted on a contract basis with
independent drilling contractors. The Company does not own any drilling
equipment.
From commencement of operations through December 31, 1996, the Company added,
net of production and property sales, approximately 109.6 MBOE of proved
reserves through purchases of reserves-in-place, discoveries of oil and natural
gas reserves, extensions of existing producing fields and revisions of
previously estimated reserves, for which the finding costs were $1.96 per BOE.
The Company's estimate of future development costs for its undeveloped proved
reserves at December 31, 1996 was $1.90 per BOE. The estimated future
development costs are based upon the Company's anticipated cost of developing
its non-producing proved reserves, which costs are calculated using historical
costs for similar activities.
<PAGE> 14
ACREAGE
The following table summarizes the developed and undeveloped acreage owned,
leased or under concession as of December 31, 1996. See Item 1. Business --
Other Properties.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
GROSS NET GROSS
NET
<S> <C> <C> <C> <C>
Venezuela 9,950 7,960 673,893 276,114
Russia 16,080 5,467 149,680 50,891
China - - 6,200,000 3,100,000
United States 5,002 1,689 10,000 6,862
------- ------ --------- ---------
Total 31,032 15,116 7,033,573 3,433,867
====== ====== ========= =========
</TABLE>
COMPETITION
The Company encounters strong competition from major oil and gas companies and
independent operators in acquiring properties and leases for exploration for
crude oil and natural gas. The principal competitive factors in the acquisition
of such oil and gas properties include the staff and data necessary to identify,
investigate and purchase such leases, and the financial resources necessary to
acquire and develop such leases. Many of the Company's competitors have
financial resources, staffs and facilities substantially greater than those of
the Company.
EMPLOYEES AND CONSULTANTS
At December 31, 1996 the Company had 55 employees augmented from time to time
with independent consultants, as required. Benton-Vinccler had 149 employees,
and GEOILBENT had 230 employees.
TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE
All Venezuelan reserves are attributable to an operating service agreement
between Benton-Vinccler and Lagoven, under which all mineral rights are owned by
the Government of Venezuela. With regard to Russian acreage, GEOILBENT has
obtained certain documentation from appropriate regulatory bodies in Russia
which the Company believes is adequate to establish GEOILBENT's right to
develop, produce and market oil and gas from the North Gubkinskoye Field in
Russia.
The WAB-21 petroleum contract covers 6.2 million acres in the South China Sea,
with an option for another one million acres under certain circumstances, and
lies within an area which is the subject of a territorial dispute between the
People's Republic of China and Vietnam. Vietnam has also executed an agreement
on a portion of the same offshore acreage with Conoco, a unit of DuPont
Corporation. The territorial dispute has existed for many years, and there has
been limited exploration and no development activity in the area under dispute.
It is uncertain when or how this dispute will be resolved, and under what terms
the various countries and parties to the agreements may participate in the
resolution, although certain proposed economic solutions currently under
discussion would result in the Company's interest being reduced.
At the time of acquisition of undeveloped acreage in the United States, the
Company conducted a limited title investigation. A title opinion from a
qualified law firm was obtained prior to drilling any given U.S. prospect. Title
to presently producing properties had been investigated by a qualified law firm
prior to purchase. The Company believes its method of investigating the title to
these domestic properties was consistent with general practices in the oil and
gas industry and was designed to enable the Company to acquire title which was
generally considered to be acceptable in the oil and gas industry.
<PAGE> 15
GLOSSARY
When the following terms are used in the text they have the meanings indicated.
MCF. "Mcf" means thousand cubic feet. "Mmcf" means million cubic feet.
"Bcf" means billion cubic feet. "Tcf" means trillion cubic feet.
BBL. "Bbl" means barrel. "MBbl" means thousand barrels. "MMBbl" means
million barrels. "Bbbl" means billion barrels.
BOE. "BOE" means barrels of oil equivalent, which are determined using the
ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf
of natural gas so that six Mcf of natural gas is referred to as one barrel of
oil equivalent or "BOE". "MBOE" means thousands of barrels of oil equivalent.
"MMBOE" means millions of barrels of oil equivalent.
CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with
exploratory and development drilling (including exploratory dry holes);
leasehold acquisitions; seismic data acquisitions; geological, geophysical and
land-related overhead expenditures; delay rentals; producing property
acquisitions; and other miscellaneous capital expenditures.
COMPLETION COSTS. "Completion Costs" means, as to any well, all those
costs incurred after the decision to complete the well as a producing well.
Generally, these costs include all costs, liabilities and expenses, whether
tangible or intangible, necessary to complete a well and bring it into
production, including installation of service equipment, tanks, and other
materials necessary to enable the well to deliver production.
DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional
well to the same reservoir as other producing wells on a lease, or drilled on an
offset lease not more than one location away from a well producing from the same
reservoir.
EXPLORATORY WELL. An "Exploratory Well" is a well drilled in search of a
new and as yet undiscovered pool of oil or gas, or to extend the known limits of
a field under development.
FINDING COST. "Finding Cost", expressed in dollars per BOE, is calculated
by dividing the amount of total capital expenditures related to acquisitions,
exploration and development costs (reduced by proceeds for any sale of oil and
gas properties) by the amount of total net reserves added or reduced as a result
of property acquisitions and sales, drilling activities and reserve revisions
during the same period.
FUTURE DEVELOPMENT COST. "Future Development Cost" of proved nonproducing
reserves, expressed in dollars per BOE, is calculated by dividing the amount of
future capital expenditures related to development properties by the amount of
total proved non-producing reserves associated with such activities.
GROSS ACRES OR WELLS. "Gross Acres or Wells" are the total acres or wells,
as the case may be, in which an entity has an interest, either directly or
through an affiliate.
LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a
producing formation to the surface, consisting of the costs incurred to operate
and maintain wells and related equipment and facilities, including labor costs,
repair and maintenance, supplies, insurance, production, severance and windfall
profit taxes.
NET ACRES OR WELLS. A party's "Net Acres" or "Net Wells" are calculated by
multiplying the number of gross acres of gross wells in which that party has an
interest by the fractional interest of the party in each such acre or well.
PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved
Developed Reserves expected to be produced from existing completion intervals
now open for production in existing wells. "Producing Properties" are properties
to which Producing Reserves have been assigned by an independent petroleum
engineer.
PROVED DEVELOPED RESERVES. "Proved Developed Reserves" are Proved Reserves
which can be expected to be recovered through existing wells with existing
equipment and operating methods.
<PAGE> 16
PROVED RESERVES. "Proved Reserves" are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known oil and gas reservoirs under existing economic and operating conditions,
that is, on the basis of prices and costs as of the date the estimate is made
and any price changes provided for by existing conditions.
PROVED UNDEVELOPED RESERVES. "Proved Undeveloped Reserves" are Proved
Reserves which can be expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion.
RESERVES. "Reserves" means crude oil and natural gas, condensate and
natural gas liquids, which are net of leasehold burdens, are stated on a net
revenue interest basis, and are found to be commercially recoverable.
ROYALTY INTEREST. A "Royalty Interest" is an interest in an oil and gas
property entitling the owner to a share of oil and gas production (or the
proceeds of the sale thereof) free of the costs of production.
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS. The "Standardized Measure
of Future Net Cash Flows" is a method of determining the present value of Proved
Reserves. The future net revenues from Proved Reserves are estimated assuming
that oil and gas prices and production costs remain constant. The resulting
stream of revenues is then discounted at the rate of 10% per year to obtain a
present value.
3-D SEISMIC. "3-D Seismic" is the method by which a three dimensional
image of the earth's subsurface is created through the interpretation of seismic
data. 3-D surveys allow for a more detailed understanding of the subsurface than
do conventional surveys and contribute significantly to field appraisal,
development and production.
UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and gas acreage
(including, in applicable instances, rights in one or more horizons which may be
penetrated by existing wellbores, but which have not been tested) to which
Proved Reserves have not been assigned by independent petroleum engineers.
ITEM 2. PROPERTIES
The principal executive offices of the Company are located in leased space in
Carpinteria, California. The lease covering this facility expires in December
2004. The Company also has other offices located in leased space, none of which
individually or in the aggregate are material. For information concerning the
location and character of the Company's oil and gas properties and interests,
see Item 1.
ITEM 3. LEGAL PROCEEDINGS
On June 13, 1994, Charles Agnew and other limited partners in several limited
partnerships formed by the Company brought an action in the Superior Court of
California, County of Ventura, against the Company for alleged actions and
omissions of the Company in operating the partnerships and alleged
misrepresentations made by the Company in selling the limited partnership
interests. The claimants seek an unspecified amount of actual and punitive
damages. On May 17, 1995, the Company agreed to a binding arbitration proceeding
with respect to such claims, which is currently in the discovery stage. The
Company will be forced to spend time and financial resources to defend or
resolve these matters. In January 1996, the Company acquired all of the
interests in three of the limited partnerships which are the subject of the
arbitration, in exchange for shares of, and warrants to purchase shares of, the
Company's common stock. In the arbitration proceeding, if any liability is found
to exist, the arbitrator will determine the amount of any damages, and may
consider all distributions made to the partners, including the consideration
received in the exchange offer, in determining the extent of damages, if any.
However, there can be no assurance that an arbitrator will consider such factors
in his or her determination of damages if the allegations are found to be true
and damages are awarded.
The Company is also subject to ordinary litigation that is incidental to its
business.
<PAGE> 17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the three month period ended December 31, 1996, no matter was submitted
to a vote of security holders.
<PAGE> 18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Company's Common Stock is traded on the NASDAQ stock market ("NASDAQ") under
the symbol "BNTN." As of December 31, 1996, there were 28,898,340 shares of
Common Stock outstanding held of record by approximately 1,074 stockholders. The
following table sets forth the high and low sales prices for the Company's
Common Stock reported on the NASDAQ.
<TABLE>
<CAPTION>
YEAR QUARTER HIGH LOW
- --------------------------------------------------------------------------
<S> <C> <C>
1995
First quarter $11.13 $ 8.63
Second quarter 15.13 10.25
Third quarter 13.88 9.50
Fourth quarter 16.13 10.13
1996
First quarter 16.63 11.25
Second quarter 22.13 15.63
Third quarter 25.38 18.38
Fourth quarter 28.63 19.75
1997
First quarter (through March 26) 24.75 14.63
</TABLE>
On March 26, 1997, the last sales price for the Common Stock as reported by
NASDAQ was $16.375 per share.
The Company's policy is to retain its earnings to support the growth of the
Company's business. Accordingly, the Board of Directors of the Company has never
declared cash dividends on its Common Stock. The Company's credit agreements
currently prohibit the declaration of any cash dividends.
<PAGE> 19
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data for the Company for each of
the five years in the period ended December 31, 1996, are derived from the
Company's audited consolidated financial statements. The consolidated financial
data below should be read in conjunction with the Company's Consolidated
Financial Statements and related notes thereto and Item 7. - Management's
Discussion and Analysis of Financial Condition and Results of Operations
contained elsewhere in this report.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------------------
1996 1995 (3) 1994 1993 1992
---------- ---------- ------------ ---------- -------
(amounts in thousands, except per share data)
STATEMENT OF OPERATIONS:
<S> <C> <C> <C> <C> <C>
Total revenues $165,066 $ 65,068 $ 34,705 $ 7,503 $ 8,622
Lease operating costs and production taxes 24,518 10,703 9,531 5,110 4,414
Depletion, depreciation and amortization 34,525 17,411 10,298 2,633 3,041
General and administrative expense 18,906 9,411 5,242 2,631 2,245
Interest expense 16,128 7,497 3,888 1,958 1,831
Partnership exchange expenses 2,140 -- -- -- --
Litigation settlement expenses -- 1,673 -- -- --
-------- -------- -------- -------- ---------
Income (loss) before income taxes, minority
interest and extraordinary charge 68,849 18,373 5,746 (4,829) (2,909)
Income tax expense 20,508 2,478 698 -- --
-------- -------- -------- -------- ---------
Income (loss) before minority interest and
extraordinary charge 48,341 15,895 5,048 (4,829) (2,909)
Minority interest 9,984 5,304 2,094 -- --
-------- -------- -------- -------- --------
Income (loss) before extraordinary charge 38,357 10,591 2,954 (4,829) (2,909)
Extraordinary charge for early retirement of
debt, net of tax benefit of $879 10,075 -- -- -- --
-------- -------- -------- -------- --------
Net income (loss) $ 28,282 $ 10,591 $ 2,954 $ (4,829) $ (2,909)
======== ======== ======== ======== =========
Net income (loss) per common share:
Primary:
Income (loss) before extraordinary $ 1.30 $ 0.40 $ 0.12 $ (0.26) $ (0.22)
charge
Extraordinary charge 0.34 -- -- -- --
-------- -------- -------- -------- ---------
Net income (loss) $ 0.96 $ 0.40 $ 0.12 $ (0.26) $ (0.22)
======== ======== ======== ======== =========
Fully diluted:
Income (loss) before extraordinary $ 1.26 $ 0.39 $ 0.12 $ (0.26) $ (0.22)
charge
Extraordinary charge 0.33 -- -- -- --
-------- -------- -------- --------- ---------
Net income (loss) $ 0.93 $ 0.39 $ 0.12 $ (0.26) $ (0.22)
======== ======== ======== ======== =========
Weighted average common shares outstanding(1):
Primary 29,590 26,673 25,314 18,609 12,981
Fully diluted 30,415 27,289 25,417 18,609 12,981
</TABLE>
<PAGE> 20
<TABLE>
<CAPTION>
AT DECEMBER 31,
---------------------------------------------------------------
1996 1995(3) 1994 1993 1992
----------- ----------- --------- --------- ----------
BALANCE SHEET DATA: (amounts in thousands)
<S> <C> <C> <C> <C> <C>
Working capital (deficit) $ 98,417 $ (2,888) $ 21,785 $ 26,635 $ 10,486
Total assets 435,745 214,750 162,561 108,635 68,217
Long-term obligations, net of current portion 175,028 49,486 31,911 11,788 13,463
Stockholders' equity (2) 174,899 103,681 88,259 84,021 50,468
<FN>
__________________________
(1) The weighted average common shares outstanding for the Company have been
adjusted for the effect of common stock equivalents for the years ended
December 31, 1996 and 1995.
(2) No cash dividends were paid during any period presented.
(3) The financial information related to Russia and included in the 1995
presentation contains information at, and for the nine months ended,
September 30, 1995, the end of the fiscal period for GEOILBENT. See Note
15 to the Consolidated Financial Statements.
</TABLE>
<PAGE> 21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS GENERAL
GENERAL
PRINCIPLES OF CONSOLIDATION AND ACCOUNTING METHODS
The Company has included the results of operations of Benton-Vinccler in its
consolidated statement of operations since January 1, 1994 and has reflected the
50% ownership interest of Vinccler during January and February 1994 and the 20%
ownership interest of Vinccler subsequent thereto as a minority interest.
Beginning in 1995, GEOILBENT has been included in the consolidated financial
statements based on a fiscal period ending September 30. Results of operations
in Russia reflect the twelve months ended December 31, 1994, the nine months
ended September 30, 1995 and the twelve months ended September 30, 1996. The
Company's investment in GEOILBENT is proportionately consolidated based on the
Company's ownership interest, and for oil and gas reserve information, the
Company reports its 34% share of the reserves attributable to GEOILBENT.
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all acquisition, exploration,
and development costs incurred. The Company accounts for its oil and gas
properties using cost centers on a country by country basis. Proceeds from sales
of oil and gas properties are credited to the full-cost pools. Capitalized costs
of oil and gas properties are amortized within the cost centers on an overall
unit-of-production method using proved oil and gas reserves as determined by
independent petroleum engineers. Costs amortized include all capitalized costs
(less accumulated amortization), the estimated future expenditures (based on
current costs) to be incurred in developing proved reserves, and estimated
dismantlement, restoration and abandonment costs. See Note 1 of Notes to
Consolidated Financial Statements.
The following discussion of the financial condition and results of operations at
December 31, 1996 and 1995 and for each of the years in the three year period
ended December 31, 1996, respectively, should be read in conjunction with the
Company's Consolidated Financial Statements and related notes thereto.
RESULTS OF OPERATIONS
The Company's results of operations for the year ended December 31, 1996
primarily reflect the substantial growth of Benton-Vinccler, C.A. in Venezuela
and the sale of the Company's U.S. operations. During 1996, Benton-Vinccler
accounted for more than 90% of the Company's production, oil and gas sales and
net income, and reported increases of more than 80% in these areas over the
corresponding period of 1995. Benton-Vinccler's significant growth has resulted
in increases in both oil and gas sales and expenses compared to the
corresponding period in 1995, although expenses have declined as a percent of
oil and gas sales as production volumes have increased. Other major influences
on the Company's results of operations during the year ended December 31, 1996
were the sale of its Gulf Coast operations, resulting in a gain of $7.2 million,
and the restructuring of its long term debt, including the issuance of $125
million of senior unsecured notes and an extraordinary charge of $11.0 million
($10.1 million net of tax benefits) related to the early retirement of certain
privately placed notes. In the first quarter of 1996, the Company completed a
partnership exchange offer, resulting in a noncash charge of $2.1 million
related to the issuance of certain warrants to purchase shares of common stock.
The following table presents selected expense items from the Company's
consolidated income statement as a percentage of oil and gas sales:
<TABLE>
<CAPTION>
1996 1995 1994
-------- ------- ------
<S> <C> <C> <C>
Lease Operating Costs and Production Taxes 16.6% 17.2% 29.8%
Depletion, Depreciation and Amortization 23.4 28.0 32.2
General and Administrative 12.8 15.1 16.4
Interest 10.9 12.1 12.2
</TABLE>
<PAGE> 22
YEARS ENDED DECEMBER 31, 1996 AND 1995
The Company had revenues of $165.1 million for the year ended December 31, 1996.
Expenses incurred during the period consisted of lease operating costs and
production taxes of $24.5 million, depletion, depreciation and amortization
expense of $34.5 million, general and administrative expense of $18.9 million,
interest expense of $16.1 million, partnership exchange expense of $2.1 million,
income tax expense of $20.5 million, minority interest of $10.0 million and an
extraordinary charge for early retirement of debt, net of tax benefit, of $10.1
million. Net income for the period was $28.3 million or $0.93 per share (fully
diluted).
By comparison, the Company had revenues of $65.1 million for the year ended
December 31, 1995. Expenses incurred during the period consisted of lease
operating costs and production taxes of $10.7 million, depletion, depreciation
and amortization expense of $17.4 million, general and administrative expense of
$9.4 million, interest expense of $7.5 million, litigation settlement expenses
of $1.7 million, income tax expense of $2.5 million and a minority interest of
$5.3 million. Net income for the period was $10.6 million or $0.39 per share
(fully diluted).
Revenues increased $100 million, or 154%, during the year ended December 31,
1996 compared to the corresponding period of 1995 primarily due to increased oil
sales in Venezuela. Sales quantities for the year ended December 31, 1996 from
Venezuela and Russia were 12,647,987 Bbl and 765,137 Bbl, respectively, compared
to 5,456,473 Bbl and 490,960 Bbl, respectively, for the year ended December 31,
1995. Prices for crude oil per Bbl averaged $10.82 (pursuant to terms of an
operating service agreement) from Venezuela and $11.83 from Russia for the year
ended December 31, 1996 compared to $9.01 and $12.25, respectively, for the year
ended December 31, 1995. Domestic sales quantities for the year ended December
31, 1996 were 6,589 Bbl of crude oil and condensate and 1,523,106 Mcf of natural
gas compared to 68,975 Bbl of crude oil and 3,784,830 Mcf of natural gas for the
year ended December 31, 1995. Domestic prices per Bbl for crude oil and per Mcf
for natural gas averaged $19.70 and $3.04 during the year ended December 31,
1996 compared to $15.79 and $1.77 during the year ended December 31, 1995.
Revenues for the year ended December 31, 1996 were reduced by a loss of $2.9
million related to a commodity hedge agreement compared to a loss of $0.7
million in 1995. Revenues for 1996 were increased by a foreign exchange gain of
$2.8 million compared to a gain of $1.0 million in 1995.
Expenses increased during 1996 as Benton-Vinccler's operations continued to grow
significantly, but decreased as a percentage of oil and gas sales. Lease
operating costs and production taxes increased $13.8 million, or 129%, during
the year ended December 31, 1996 compared to 1995, partially offset by the sale
of the Company's remaining interest in the West Cote Blanche Bay, Rabbit Island
and Belle Isle Fields. Depletion, depreciation and amortization increased $17.1
million, or 98%, during the year ended December 31, 1996 compared to the
corresponding period in 1995. Depletion expense per BOE produced from Venezuela,
United States and Russia during the year ended December 31, 1996 was $2.33,
$6.55 and $3.59, respectively, compared to $2.09, $5.98 and $3.08, respectively,
during the previous year. The increase in general and administrative expenses of
$9.5 million, or 101%, during the year ended December 31, 1996 compared to 1995
was primarily due to the implementation of certain consulting and related
arrangements among Benton-Vinccler, the Company and Vinccler, Venezuelan
municipal taxes (which are a function of growing oil revenues) and the Company's
increased corporate activity associated with the growth of the Company's
business. Interest expense increased $8.6 million, or 115%, in 1996 compared to
1995 primarily due to the issuance of $125 million in senior unsecured notes in
May 1996. The Company incurred partnership exchange expense of $2.1 during the
year ended December 31, 1996 as a result of the completion of an exchange offer
resulting in the liquidation of three limited partnerships (see Note 2 of Notes
to the Consolidated Financial Statements). Income tax expense increased $18.0
million, or 720%, during the year ended December 31, 1996 compared to 1995
primarily due to increased taxable income in Venezuela. The net income
attributable to the minority interest increased $4.7 million, or 89%, for 1996
compared to 1995 as a result of the increased profitability of Benton-Vinccler's
operations in Venezuela.
YEARS ENDED DECEMBER 31, 1995 AND 1994
The Company had revenues of $65.1 million for the year ended December 31, 1995.
Expenses incurred during the period consisted of lease operating costs and
production taxes of $10.7 million, depletion, depreciation and amortization
expense of $17.4 million, general and administrative expense of $9.4 million,
interest expense of $7.5 million, litigation settlement expenses of $1.7
million, income tax expense of $2.5 million and a minority interest of $5.3
million. Net income for the period was $10.6 million or $0.40 per share.
<PAGE> 23
By comparison, the Company had revenues of $34.7 million for the year ended
December 31, 1994. Expenses incurred during the period consisted of lease
operating costs and production taxes of $9.5 million, depletion, depreciation
and amortization expense of $10.3 million, general and administrative expense of
$5.2 million, interest expense of $3.9 million, income tax expense of $0.7
million and a minority interest of $2.1 million. The net income for the period
was $3.0 million or $0.12 per share.
Revenues increased $30.4 million, or 88%, during the year ended December 31,
1995 compared to the corresponding period of 1994 primarily due to increased oil
sales in Venezuela. Sales quantities for the year ended December 31, 1995 from
Venezuela and Russia were 5,456,473 and 490,960 Bbl, respectively, compared to
2,519,514 and 294,364, respectively, for the year ended December 31, 1994.
Prices per Bbl for crude oil averaged $9.01 (pursuant to terms of an operating
service agreement) from Venezuela and $12.25 from Russia for the year ended
December 31, 1995 compared to $8.52 and $11.93, respectively, for the year ended
December 31, 1994. Domestic sales quantities for the year ended December 31,
1995 were 68,975 Bbl of crude oil and condensate and 3,784,830 Mcf of natural
gas compared to 225,954 Bbl of crude oil and 2,061,892 Mcf of natural gas for
the year ended December 31, 1994. Domestic prices per Bbl for crude oil and per
Mcf for natural gas averaged $15.79 and $1.77 during the year ended December 31,
1995 compared to $14.46 and $1.79 during the year ended December 31, 1994.
Revenues for the year ended December 31, 1995 were reduced by a loss of $0.7
million related to a commodity hedge agreement compared to $0.3 million in 1994.
1995 revenues were increased by a foreign exchange gain of $1.0 million compared
to a gain of $1.4 million in 1994.
Lease operating costs and production taxes increased $1.2 million, or 13%,
during the year ended December 31, 1995 compared to the corresponding period of
1994 primarily due to the growth of the Company's Venezuelan operations,
partially offset by the sale of certain of the Company's interest in the West
Cote Blanche Bay Field, but decreased significantly as a percentage of oil and
gas sales. Depletion, depreciation and amortization increased $7.1 million, or
69%, during the year ended December 31, 1995 compared to the corresponding
period in 1994 primarily due to the increased oil production in Venezuela.
Depletion expense per BOE produced from Venezuela, United States and Russia
during the year ended December 31, 1995 was $2.09, $5.98 and $3.08,
respectively, compared to $1.98, $7.46 and $2.85, respectively, during the
previous year. The increase in general and administrative expenses of $4.2
million, or 81%, during the year ended December 31, 1995 compared to 1994 was
primarily due to the Company's increased corporate activity associated with the
growth of the Company's business, but decreased slightly as a percentage of oil
and gas sales. The Company incurred litigation settlement expenses of $1.7
million during the year ended December 31, 1995 as a result of a settlement
agreement reached with investors in partnerships which were sponsored by a third
party (see Note 5 of Notes to the Consolidated Financial Statements). Interest
expense increased $3.6 million, or 93%, in 1995 compared to 1994 primarily due
to increased borrowing to fund operations in Venezuela and Russia. Income tax
expense increased $1.8 million, or 257%, during the year ended December 31, 1995
compared to 1994 primarily due to increased income taxes in Venezuela and
Russia. The net income attributable to the minority interest increased $3.2
million, or 152%, for 1995 compared to 1994 as a result of the increased
profitability of Benton-Vinccler's operations in Venezuela.
INTERNATIONAL OPERATIONS
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%. However, Benton-Vinccler reported significantly lower effective tax
rates for 1995 and 1996 due to significant non-cash tax deductible expenses
resulting from devaluations in Venezuela when Benton-Vinccler had net monetary
liabilities in U.S. dollars. The Company cannot predict the timing or impact of
future devaluations in Venezuela. Any Company operations related to Delta Centro
will be subject to oil and gas industry taxation, which currently provides for
royalties of 16.67% and income taxes of 66.67%. See Item 1. Business -- Delta
Centro Block, Venezuela.
GEOILBENT is subject to a statutory income tax rate of 35%. GEOILBENT has also
been subject to various other tax burdens, including an oil export tariff. For
the year ended December 31, 1994 and the period January 1 through June 30, 1996,
the Company recorded an expense for the Russian export tariff of $1,397,317 and
$845,385, respectively, which is included in lease operating expenses and
production taxes. GEOILBENT received a waiver from the export tariff for 1995
and in July 1996, such oil export tariffs were terminated in conjunction with a
loan agreement with the International Monetary Fund. Excise, pipeline and other
taxes continue to be levied on all oil producers and certain exporters. The
Russian regulatory environment continues to be volatile and the Company is
unable to predict the impact of taxes, duties and other burdens for the future.
<PAGE> 24
During 1996, the Company acquired Crestone Energy Corporation, a privately held
company headquartered in Denver, Colorado, for 628,142 shares of common stock
and options to purchase 107,571 shares of the Company's common stock at $7.00
per share, valued at $14.6 million. Crestone's principal asset is a petroleum
contract with China National Offshore Oil Company for an area known as Wan'An
Bei, WAB-21. The WAB-21 petroleum contract covers 6.2 million acres in the South
China Sea, with an option for another one million acres under certain
circumstances, and lies within an area which is the subject of a territorial
dispute between the People's Republic of China and Vietnam. Vietnam has also
executed an agreement on a portion of the same offshore acreage with Conoco, a
unit of DuPont Corporation. The territorial dispute has existed for many years,
and there has been limited exploration and no development activity in the area
under dispute. It is uncertain when or how this dispute will be resolved, and
under what terms the various countries and parties to the agreements may
participate in the resolution, although certain proposed economic solutions
currently under discussion would result in the Company's interest being reduced.
The Company, through Crestone, has submitted plans and budgets to CNOOC for an
initial seismic program to survey the area, however, exploration activities will
be subject to resolution of such territorial dispute. The Company has recorded
no reserves attributable to this petroleum contract
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION
The Company's results of operations and cash flow are affected by changing oil
and gas prices. However, the Company's Venezuelan revenues are based on a fee
adjusted quarterly by the percentage change of a basket of crude oil prices
instead of by absolute dollar changes, which dampens both any upward and
downward effects of changing prices on the Company's Venezuelan revenues and
cash flows. If the price of oil and gas increases, there could be an increase in
the cost to the Company for drilling and related services because of increased
demand, as well as an increase in revenues. Fluctuations in oil and gas prices
may affect the Company's total planned development activities and capital
expenditure program.
Effective May 1, 1994, the Company entered into a commodity hedge agreement with
Morgan Guaranty designed to reduce a portion of the Company's risk from oil
price movements through December 31, 1996. Pursuant to the hedge agreement, with
respect to the period from May 1, 1994 through the end of 1996, the Company
received from Morgan Guaranty $16.82 per Bbl and the Company paid to Morgan
Guaranty the average price per Bbl of West Texas Intermediate Light Sweet Crude
Oil ("WTI") determined in the manner set forth in the hedge agreement. Such
payments were made with respect to production of 1,000 Bbl of oil per day for
1994, 1,250 Bbl of oil per day for 1995, and 1,500 Bbl of oil per day for 1996.
During the quarter ended December 31, 1996, the average price per Bbl of WTI was
$24.57 and the Company's net exposure for the quarter was $1.1 million. The
Company's total exposure for the year ended December 31, 1996, under the hedge
agreement was $2.9 million.
There are presently no restrictions in either Venezuela or Russia that restrict
converting U.S. dollars into local currency. However, during 1994, Venezuela
implemented exchange controls which significantly limited the ability to convert
local currency into U.S. dollars. Because payments made to Benton-Vinccler are
made in U.S. dollars into its United States bank account, and Benton-Vinccler is
not subject to regulations requiring the conversion or repatriation of those
dollars back into the country, the exchange controls did not have a material
adverse effect on Benton-Vinccler or the Company. Currently, there are no
exchange controls in Venezuela or Russia that restrict conversion of local
currency into U.S. dollars.
Within the United States, inflation has had a minimal effect on the Company, but
it is potentially an important factor in results of operations in Venezuela and
Russia. With respect to Benton-Vinccler and GEOILBENT, substantially all of the
sources of funds, including the proceeds from oil sales, the Company's
contributions and credit financings, are denominated in U.S. dollars, while
local transactions in Russia and Venezuela are conducted in local currency. If
the rate of increase in the value of the dollar compared to the bolivar
continues to be less than the rate of inflation in Venezuela, then inflation
could be expected to have an adverse effect on Benton-Vinccler.
During the year ended December 31, 1996, the Company realized net foreign
exchange gains, primarily as a result of the decline in the value of the
Venezuelan bolivar and the Russian rouble during periods when Benton-Vinccler
and GEOILBENT had substantial net monetary liabilities denominated in bolivares
and roubles. During the year ended December 31, 1996, the Company's net foreign
exchange gains attributable to its Venezuelan and Russian operations were $1.8
million and $1.0 million, respectively. However, there are many factors
affecting foreign exchange rates and resulting exchange gains and losses, many
of which are beyond the control of the Company. The Company has recognized
significant exchange gains and losses in the past, resulting from fluctuations
in the
<PAGE> 25
relationship of the Venezuelan and Russian currencies to the U.S. dollar. It is
not possible to predict the extent to which the Company may be affected by
future changes in exchange rates and exchange controls.
CAPITAL RESOURCES AND LIQUIDITY
The oil and gas industry is a highly capital intensive business. The Company
requires capital principally to fund the following costs: (i) drilling and
completion costs of wells and the cost of production and transportation
facilities; (ii) geological, geophysical and seismic costs; and (iii)
acquisition of interests in oil and gas properties. The amount of available
capital will affect the scope of the Company's operations and the rate of its
growth.
The net funds raised and/or used in each of the operating, investing and
financing activities for each of the years in the three year period ended
December 31, 1996 are summarized in the following table and discussed in further
detail below:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------------------------------
1996 1995 1994
-------------- ------------ -------------
<S> <C> <C> <C>
Net cash provided by operating activities $ 84,852,307 $ 32,349,456 $ 13,462,789
Net cash used in investing activities (164,772,501) (53,643,733) (55,078,138)
Net cash provided by financing activities 106,171,905 13,281,707 19,499,799
-------------- ------------- -------------
Net increase (decrease) in cash $ 26,251,711 $ (8,012,570) $(22,115,550)
============== ============== =============
</TABLE>
At December 31, 1996, the Company had current assets of $150.5 million
(including $4.5 million of cash restricted as collateral for a loan to
GEOILBENT), and current liabilities of $52.1 million (including a $1.0 million
loan collateralized by restricted cash), resulting in working capital of $98.4
million and a current ratio of 2.9:1. This compares to the Company's working
capital deficit of $2.9 million at December 31, 1995. The increase of $101.3
million was due primarily to the issuance of $125 million of senior unsecured
notes, net of repayment of certain indebtedness.
CASH FLOW FROM OPERATING ACTIVITIES. During 1996, 1995 and 1994, net cash
provided by operating activities was approximately $84.9 million, $32.4 million
and $13.5 million, respectively. Cash flow from operating activities increased
by $52.5 million and $18.9 million in 1996 and 1995, respectively, over the
prior years due primarily to increased oil and gas production in Venezuela.
CASH FLOW FROM INVESTING ACTIVITIES. During 1996, 1995 and 1994, the Company had
drilling and production related capital expenditures of approximately $96.1
million, $68.3 million and $39.6 million, respectively. Of the 1996
expenditures, $84.5 million was attributable to the development of the South
Monagas Unit in Venezuela, $6.0 million related to the development of the North
Gubkinskoye Field in Russia, $1.9 million related to drilling activity in the
West Cote Blanche Bay, Rabbit Island and Belle Isle Fields in Louisiana, and
$3.7 million was attributable to other projects. The Company also sold certain
oil and gas properties for net proceeds of approximately $34.6 million, $15.4
million and $5.8 million in 1996, 1995 and 1994, respectively.
In April 1996, the Company sold to Shell all of its interests in the West Cote
Blanche Bay, Rabbit Island and Belle Isle Fields for a purchase price of $35.4
million. Proceeds of the sale were used to repay debt as described below and for
working capital purposes in Venezuela and other international activities.
CASH FLOW FROM FINANCING ACTIVITIES. In May 1996, the Company issued $125
million in 11.625% senior unsecured notes due May 1, 2003. Interest on the notes
is due May 1 and November 1 of each year, beginning November 1, 1996. The
indenture agreement provides for certain limitations on liens, additional
indebtedness, certain investment and capital expenditures, dividends, mergers
and sales of assets. At December 31, 1996, the Company was in compliance with
all covenants of the indenture. A portion of the proceeds from the notes was
used to repay certain long term indebtedness and certain short term obligations,
and the remainder has been or will be used for capital expenditure and working
capital purposes. (see Note 3 of Notes to Consolidated Financial Statements.)
Also, in May 1996, the Company entered into an agreement with Morgan Guaranty
which provides for a $20 million revolving credit facility and an $18 million
cash collateralized 5-year letter of credit to secure the Company's performance
of the minimum exploration work program required in the Delta Centro Block in
Venezuela. The revolving credit facility could be drawn upon until December
1996, with interest at LIBOR plus 3% through June
<PAGE> 26
1997 and LIBOR plus 3.75% thereafter. Any amount outstanding at the end of the
revolving period would automatically convert into a term loan due 15 months
thereafter. The credit facility contains financial covenants requiring that the
Company maintain a current ratio of at least 1.1 to 1.0 and a minimum net worth
of $100 million at the end of each fiscal quarter. No amounts were drawn under
the credit facility in 1996.
In August 1996, Benton-Vinccler entered into a $50 million, 2-year credit
facility with Morgan Guaranty Trust Company of New York ("Morgan Guaranty") to
repay the balance outstanding under a short term credit facility (see Note 3 of
Notes to Consolidated Financial Statements) and to repay certain advances
received from the Company. The credit facility is collateralized in full by a
time deposit of the Company and bears interest at LIBOR plus 6%. The Company
will receive interest on its time deposit and a security fee on the outstanding
principal of the loan, for a combined total of approximately LIBOR plus 5.75%.
The loan arrangement contains no restrictive covenants and no financial ratio
covenants.
The Company expects 1997 capital expenditures to be approximately $140 million,
including $19 million in expenditures for Russia (net to the Company's
interest), which is dependent on EBRD or other financing (see Item
1.Business--North Gubkinskoye, Russia--Drilling and Development Activity).
Funding is expected to come from the issuance of debt or equity securities, cash
flow from operations, sales of property interests, or project and trade
financing sources. There can be no assurance that such financing will become
available under terms and conditions acceptable to the Company, which may result
in reduced capital expenditures in the Company's principal areas of operations.
The Company continues to evaluate and pursue domestic and international
opportunities which fit within the Company's business strategy. The Company is
currently evaluating certain development and/or acquisition opportunities, but
it is not presently known whether, or on what terms, such evaluations will
result in future agreements or acquisitions.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The information required by this item is included herein on pages S-1 through
S-25.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported under this item.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
*
ITEM 11. EXECUTIVE COMPENSATION
*
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
*
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
*
* Reference is made to information under the captions "Election of
Directors", "Executive Officers", "Executive Compensation", "Security
Ownership of Certain Beneficial Owners and Management", and "Certain
Relationships and Related Transactions" in the Company's Proxy Statement
for the 1997 Annual Meeting of Stockholders.
<PAGE> 27
PART IV
<TABLE>
<CAPTION>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Index to Financial Statements: Page
----
<S> <C> <C>
Independent Auditors' Report ...............................................S-1
Consolidated Balance Sheets at December 31, 1996 and 1995 ..................S-2
Consolidated Statements of Income for the Years Ended
December 31, 1996, 1995 and 1994 ...........................................S-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1996, 1995 and 1994 ...............................S-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1996, 1995 and 1994 ...........................................S-5
Notes to Consolidated Financial Statements for the Years
Ended December 31, 1996, 1995 and 1994 .....................................S-7
2. Consolidated Financial Statement Schedules:
Schedules for which provision is made in Regulation S-X are not
required under the instructions contained therein, are inapplicable, or
the information is included in the footnotes to the financial
statements.
3. Exhibits:
3.1 Certificate of Incorporation of the Company filed September 9, 1988.*
3.2 Amendment to Certificate of Incorporation of the Company filed June 7, 1991.**
3.3 Restated Bylaws of the Company.
4.1 Form of Common Stock Certificate.*
10.4 Form of Employment Agreements (Exhibit 10.19).*
10.7 Benton Oil and Gas Company 1991-1992 Stock Option Plan (Exhibit 10.14).***
10.8 Benton Oil and Gas Company Directors' Stock Option Plan (Exhibit 10.15).***
10.9 Agreement dated October 16, 1991 among Benton Oil and Gas
Company, Puror State Geological Enterprises for Survey,
Exploration, Production and Refining of Oil and Gas; and Puror
Oil and Gas Production Association (Exhibit 10.14)****
10.10 Operating Service Agreement between the Company and Lagoven,
S.A., dated July 31, 1992, (portions have been omitted pursuant
to Rule 406 promulgated under the Securities Act of 1933 and
filed separately with the Securities and Exchange
Commission--Exhibit 10.15).*****
10.11 Letter Agreement between Benton Oil and Gas Company and Vinccler, C.A., dated February 9, 1994 (Exhibit
10.16). ******
</TABLE>
<PAGE> 28
<TABLE>
<S> <C>
10.15 Stock Purchase and Sale Agreement by and between Benton Oil and
Gas Company and Shell Offshore, Inc. Re: Benton Oil and Gas
Company of Louisiana dated effective as of December 31, 1995
(Incorporated by reference to Exhibit 2.1 to the Company's
Current Reports on Form 8-K filed March 27, 1996.)
10.16 Indenture dated May 2, 1996 between Benton Oil and Gas Company
and First Trust of New York, National Association, Trustee
related to $125,000,000, 11 5/8% Senior Notes Due 2003
(Incorporated by reference to Exhibit 4.1 to the Company's S-4
Registration Statement filed June 17, 1996, SEC Registration
No. 333-06125).
11.1 Computation of per share earnings.
21.1 List of subsidiaries.
23.1 Consent of Deloitte & Touche LLP.
23.2 Consent of Huddleston & Co., Inc.
27.1 Financial Data Schedule
__________________________
* Previously filed as an exhibit to the Company's S-1 Registration Statement (Registration No. 33-26333).
** Previously filed as an exhibit to the Company's S-1 Registration Statement (Registration No. 33-39214).
*** Previously filed as an exhibit to the Company's S-1 Registration Statement (Registration No. 33-43662).
**** Previously filed as an exhibit to the Company's S-1 Registration Statement (Registration No. 33-46077).
***** Previously filed as an exhibit to the Company's S-1 Registration Statement (Registration No. 33-52436).
****** Previously filed as an exhibit to the Company's Form 8-K report dated February 9, 1994.
(b) Reports on Form 8-K
No Form 8-K was filed during the last quarter of the registrant's fiscal year.
</TABLE>
<PAGE> 29
INDEPENDENT AUDITORS' REPORT
- ----------------------------
Board of Directors and Stockholders
Benton Oil and Gas Company
Carpinteria, California
We have audited the accompanying consolidated balance sheets of Benton Oil and
Gas Company and subsidiaries (the "Company") as of December 31, 1996 and 1995,
and the related consolidated statements of income, stockholders' equity, and
cash flows for each of the three years in the period ended December 31, 1996.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Benton Oil and Gas Company and
subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996 in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Los Angeles, California
March 20, 1997
<PAGE> 30
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
---------------------------
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1996 1995
------------- -------------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents $ 32,431,709 $ 6,179,998
Restricted cash 4,500,000 20,314,000
Marketable securities 52,003,995
Accounts receivable:
Accrued oil and gas revenue 50,136,980 22,069,217
Joint interest and other 9,860,512 2,869,962
Prepaid expenses and other 1,591,488 214,622
------------- -------------
TOTAL CURRENT ASSETS 150,524,684 51,647,799
RESTRICTED CASH 68,000,000
OTHER ASSETS 6,185,878 3,434,760
PROPERTY AND EQUIPMENT:
Oil and gas properties (full cost method - costs of
$25,986,981 and $17,925,371 excluded from
amortization in 1996 and 1995, respectively) 259,621,781 177,110,550
Furniture and fixtures 4,283,074 2,539,233
------------- -------------
263,904,855 179,649,783
Accumulated depletion and depreciation (52,870,176) (19,982,244)
------------- -------------
211,034,679 159,667,539
------------- -------------
$ 435,745,241 $ 214,750,098
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable:
Revenue distribution $ 305,356 $ 2,692,751
Trade and other 42,952,001 19,777,018
Accrued interest payable, payroll and related taxes 5,975,417 1,687,648
Income taxes payable 888,638 1,039,166
Short term borrowings 853,452 21,905,480
Current portion of long term debt 1,132,516 7,433,339
------------- -------------
TOTAL CURRENT LIABILITIES 52,107,380 54,535,402
DEFERRED INCOME TAXES 16,678,612
LONG TERM DEBT 175,028,205 49,486,306
MINORITY INTEREST 17,031,848 7,047,791
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, par value $0.01 a share; authorized
5,000,000 shares; outstanding, none
Common stock, par value $0.01 a share;
authorized 40,000,000 shares; issued and
outstanding 28,898,340 and 25,508,605 shares at
December 31, 1996 and 1995, respectively 288,983 255,086
Additional paid-in capital 140,648,484 97,745,794
Retained earnings 33,961,729 5,679,719
------------- -------------
TOTAL STOCKHOLDERS' EQUITY 174,899,196 103,680,599
------------- -------------
$ 435,745,241 $ 214,750,098
============= =============
</TABLE>
See notes to consolidated financial statements.
S-2
<PAGE> 31
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
---------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
REVENUES
Oil and gas sales $147,703,421 $62,156,694 $31,942,810
Gain on sale of properties 7,174,904
Net gain on exchange rates 2,819,930 997,820 1,445,307
Investment earnings and other 7,368,243 1,913,144 1,316,689
------------ ----------- -----------
165,066,498 65,067,658 34,704,806
------------ ----------- -----------
EXPENSES
Lease operating costs and production taxes 24,517,563 10,702,797 9,531,264
Depletion, depreciation and amortization 34,525,413 17,411,089 10,298,112
General and administrative 18,905,936 9,410,187 5,241,295
Interest 16,128,442 7,497,187 3,887,961
Partnership exchange expenses 2,139,655
Litigation settlement expenses 1,673,272
------------ ----------- -----------
96,217,009 46,694,532 28,958,632
------------ ----------- -----------
INCOME BEFORE INCOME TAXES AND MINORITY
INTEREST 68,849,489 18,373,126 5,746,174
INCOME TAXES 20,508,623 2,477,960 697,802
------------ ----------- -----------
INCOME BEFORE MINORITY INTEREST 48,340,866 15,895,166 5,048,372
MINORITY INTEREST 9,984,057 5,304,131 2,094,211
------------ ----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE 38,356,809 10,591,035 2,954,161
EXTRAORDINARY CHARGE FOR EARLY RETIREMENT OF
DEBT, NET OF TAX BENEFIT OF $879,000 10,074,799
------------ ----------- -----------
NET INCOME $ 28,282,010 $10,591,035 $ 2,954,161
============ =========== ===========
NET INCOME PER COMMON SHARE:
Primary:
Income before extraordinary charge $ 1.30 $ 0.40 $ 0.12
Extraordinary charge 0.34
------------ ----------- -----------
Net Income $ 0.96 $ 0.40 $ 0.12
============ =========== ===========
Fully Diluted:
Income before extraordinary charge $ 1.26 $ 0.39 $ 0.12
Extraordinary charge 0.33
------------ ----------- -----------
Net Income $ 0.93 $ 0.39 $ 0.12
============ =========== ===========
</TABLE>
See notes to consolidated financial statements.
S-3
<PAGE> 32
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-----------------------------------------------
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
<CAPTION>
COMMON RETAINED
SHARES COMMON ADDITIONAL PAID-IN EARNINGS
ISSUED STOCK CAPITAL (DEFICIT) TOTAL
-------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
BALANCE AT JANUARY 1, 1994 24,676,848 $246,768 $91,639,606 $(7,865,477) $84,020,897
Issuance of common shares:
Exercise of stock options 23,000 230 83,509 83,739
Acquisitions 200,000 2,000 1,198,000 1,200,000
Net income 2,954,161 2,954,161
---------- -------- ------------ ----------- ------------
BALANCE AT DECEMBER 31, 1994 24,899,848 248,998 92,921,115 (4,911,316) 88,258,797
Issuance of common shares:
Exercise of warrants 3,155 32 28,663 28,695
Exercise of stock options 272,580 2,726 1,335,330 1,338,056
Conversion of notes and
debentures 333,022 3,330 3,506,713 3,510,043
Securities registration costs (46,027) (46,027)
Net income 10,591,035 10,591,035
---------- -------- ------------ ----------- ------------
BALANCE AT DECEMBER 31, 1995 25,508,605 255,086 97,745,794 5,679,719 103,680,599
Issuance of common shares:
Exercise of warrants 993,644 9,936 12,134,064 12,144,000
Exercise of stock options 888,634 8,886 5,941,322 5,950,208
Conversion of notes and
debentures 710,953 7,109 6,870,655 6,877,764
Acquisitions 796,504 7,966 18,573,986 18,581,952
Securities registration costs (617,337) (617,337)
Net income 28,282,010 28,282,010
---------- -------- ------------ ----------- ------------
BALANCE AT DECEMBER 31, 1996 28,898,340 $288,983 $140,648,484 $33,961,729 $174,899,196
========== ======== ============ =========== ============
</TABLE>
See notes to consolidated financial statements.
S-4
<PAGE> 33
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------
1996 1995 1994
-------------- -------------- -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 28,282,010 $ 10,591,035 $ 2,954,161
Adjustments to reconcile net income to net cash provided by operating
activities:
Depletion, depreciation and amortization 34,525,413 17,411,089 10,298,112
Net earnings from limited partnerships (57,685) (63,486)
Amortization of financing costs 669,997 184,447 114,311
(Gain) loss on disposition of assets (6,949,904) 16,211
Partnership exchange expenses 2,139,655
Minority interest in undistributed earnings of subsidiary 9,984,057 5,304,131 2,094,211
Extraordinary charge for early retirement of debt 10,074,799
Deferred income taxes 16,678,612
Changes in operating assets and liabilities:
Accounts receivable (35,179,868) (12,882,072) (10,384,670)
Prepaid expenses and other (1,376,866) 349,217 (84,905)
Accounts payable 20,991,092 9,905,365 7,974,335
Accrued interest payable, payroll and related taxes 4,287,769 488,552 560,720
Income taxes payable 725,541 1,039,166
------------ ------------- -----------
NET CASH PROVIDED BY OPERATING ACTIVITIES 84,852,307 32,349,456 13,462,789
------------ ------------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and equipment 34,637,513 15,408,368 5,803,215
Additions of property and equipment (95,497,488) (68,288,101) (39,631,547)
Increase in restricted cash (74,050,000) (1,864,000) (19,250,000)
Decrease in restricted cash 21,864,000 1,100,000
Purchases of marketable securities (133,296,015)
Maturities of marketable securities 81,292,020
Distributions from limited partnerships 277,469 502,167
Payment for purchase of Benton-Vinccler, net of cash acquired (2,501,973)
------------ ------------- -----------
NET CASH USED IN INVESTING ACTIVITIES (164,772,501) (53,643,733) (55,078,138)
------------ ------------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from exercise of stock options and warrants 17,818,242 1,319,767 83,740
Proceeds from issuance of notes payable 181,920,954 22,157,500 21,360,000
Proceeds from short term borrowings 2,400,000 23,217,775
Payments on short term borrowings and notes payable (76,468,561) (11,999,336) (24,706,358)
Prepayment premiums on debt retirement (10,632,400)
Increase in other assets (6,466,330) (596,224) (455,358)
------------ ------------- -----------
NET CASH PROVIDED BY FINANCING ACTIVITIES 106,171,905 13,281,707 19,499,799
------------ ------------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALANTS 26,251,711 (8,012,570) (22,115,550)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 6,179,998 14,192,568 36,308,118
------------ ------------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 32,431,709 $ 6,179,998 $14,192,568
============ ============= ===========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for interest expense $ 13,519,295 $ 7,011,623 $ 3,299,189
============ ============= ===========
Cash paid during the year for income taxes $ 3,286,842 $ 1,885,291 $ 715,507
============ ============= ===========
</TABLE>
See notes to consolidated financial statements.
S-5
<PAGE> 34
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the year ended December 31, 1996, the Company acquired Crestone Energy
Corporation ("Crestone"), a privately held corporation headquartered in Denver,
Colorado, for 628,142 shares of common stock and options to purchase 107,571
shares of the Company's common stock at $7.00 per share, valued at $14.6
million.
During the year ended December 31, 1996, $3,226,000 principal amount of the
Company's 8% convertible notes and $4,310,000 principal amount of the Company's
8% convertible debentures were retired upon conversion into 275,081 and 435,872
shares of the Company's common stock, respectively.
During the year ended December 31, 1996, the Company financed the purchase of
oil and gas equipment and services in the amount of $272,655. Also during the
year ended December 31, 1996, the Company acquired the partners' interests in
each of the three limited partnerships sponsored by the Company in exchange for
an aggregate of 168,362 shares of the Company's common stock and warrants to
purchase 587,783 shares of common stock at $11.00 per share, with a total value
of $3,996,601.
During the year ended December 31, 1995, $1,393,000 of the Company's 8%
convertible notes and $2,118,000 of the Company's 8% convertible debentures were
retired in exchange for 118,785 and 214,237 shares of the Company's common
stock, respectively.
During the year ended December 31, 1995, the Company financed the purchase of
oil and gas equipment and services in the amount of $10,384,809 and leased
office equipment in the amount of $54,473. Also during 1995, the Company
acquired residential real estate for $1,725,000 in exchange for accounts and
notes receivable from an officer of the Company totaling $1,181,483 resulting in
an account payable of $543,517 (see Note 12).
During the year ended December 31, 1994, the Company converted $143,658 of
accounts payable into a note payable, financed the purchase of computer
equipment in the amount of $105,000 and financed the purchase of oil and gas
equipment in the amount of $1,733,675.
On March 4, 1994, the Company acquired capital stock from Vinccler representing
an additional 30% ownership interest in Benton-Vinccler for $3 million in cash,
$10 million in non-interest bearing notes payable (with a present value of $9.2
million assuming a 10% interest rate) and 200,000 shares of the Company's common
stock. The excess of the purchase price over the net book value of assets
acquired was $13,880,100, which was allocated to oil and gas properties.
See notes to consolidated financial statements.
S-6
<PAGE> 35
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
Benton Oil and Gas Company (the "Company") engages in the exploration,
development, production and management of oil and gas properties.
The Company and its subsidiary, Benton Oil and Gas Company of Louisiana,
participated as the managing general partner of three oil and gas limited
partnerships formed during 1989 through 1991. Under the provisions of the
limited partnership agreements, the Company received compensation as stipulated
therein, and functioned as an agent for the partnerships to arrange for the
management, drilling, and operation of properties, and assumed customary
contingent liabilities for partnership obligations. In January 1996, the Company
acquired the limited partnership interests for an aggregate of 168,362 shares of
common stock and warrants to purchase 587,783 shares of common stock at $11 per
share, and liquidated the partnerships (see Note 2).
The consolidated financial statements include the accounts of the Company and
its subsidiaries. The Company's investments in limited partnerships and the
Russia joint venture ("GEOILBENT") are proportionately consolidated based on the
Company's ownership interest. Beginning in 1995, GEOILBENT (owned 34% by the
Company) has been included in the consolidated financial statements based on a
fiscal period ending September 30. This change was made to provide adequate time
for the accumulation and review of financial information from the joint venture
for both quarterly and annual reporting purposes. This change did not have a
material effect on the consolidated financial statements (see Note 15). All
material intercompany profits, transactions and balances have been eliminated.
CASH AND CASH EQUIVALENTS
Cash equivalents include money market funds and short term certificates of
deposit with original maturity dates of less than three months.
MARKETABLE SECURITIES
Marketable securities are carried at amortized cost. They may be comprised of
high-grade debt instruments, demand or time deposits, bankers' acceptances and
certificates of deposit or acceptances of large U.S. financial institutions and
commercial paper of highly rated U.S. corporations; all having maturities of no
more than 180 days. At December 31, 1996, the Company's marketable securities at
cost, which approximates fair value, consisted of $26.2 million in treasury
securities or repurchase agreements therefore, $19.8 million in commercial paper
and $6.0 million in bankers' acceptances.
ACCOUNTS RECEIVABLE
The Company has recorded an allowance for doubtful accounts of $335,803 related
to other accounts receivable at December 31, 1996. No allowance was considered
necessary at December 31,1995.
OTHER ASSETS
Other assets consist principally of costs associated with the issuance of long
term debt and at December 31, 1995 residential real estate held for sale which
the Company sold in 1996. Debt issuance costs are amortized on a straight-line
basis over the life of the debt.
S-7
<PAGE> 36
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for oil and gas
properties. Accordingly, all costs associated with the acquisition, exploration,
and development of oil and gas reserves are capitalized as incurred, including
exploration overhead of $1,441,344, $2,282,194 and $1,696,330 for the years
ended December 31, 1996, 1995 and 1994, respectively. Only overhead which is
directly identified with acquisition, exploration or development activities is
capitalized. All costs related to production, general corporate overhead and
similar activities are expensed as incurred. The costs of oil and gas properties
are accumulated in cost centers on a country by country basis, subject to a cost
center ceiling (as defined by the Securities and Exchange Commission).
All capitalized costs of oil and gas properties (excluding unevaluated property
acquisition and exploration costs) and the estimated future costs of developing
proved reserves, are depleted over the estimated useful lives of the properties
by application of the unit-of-production method using only proved oil and gas
reserves. Depletion expense attributable to the Venezuelan cost center for the
years ended December 31, 1996, 1995 and 1994 was $29,523,300, $11,392,777 and
$4,998,213 ($2.33, $2.09 and $1.98 per equivalent barrel), respectively.
Depletion expense attributable to the Russian cost center for the years ended
December 31, 1996, 1995 and 1994 was $2,747,304, $1,512,821 and $837,818 ($3.59,
$3.08 and $2.85 per equivalent barrel), respectively. Depletion expense
attributable to the United States cost center for the years ended December 31,
1996, 1995 and 1994 was $1,704,940, $4,187,440 and $4,247,303 ($6.55, $5.98 and
$7.46 per equivalent barrel), respectively. Depreciation of furniture and
fixtures is computed using the straight-line method, with depreciation rates
based upon the estimated useful life applied to the cost of each class of
property. Depreciation expense was $548,000, $310,038 and $185,336 for the years
ended December 31, 1996, 1995 and 1994, respectively.
TAXES ON INCOME
Deferred income taxes reflect the net tax effects, calculated at currently
effective rates, of (a) future deductible/taxable amounts attributable to events
that have been recognized on a cumulative basis in the financial statements and
(b) operating loss and tax credit carryforwards. A valuation allowance is
recorded, if necessary, to reduce net deferred income tax assets to the amount
expected to be recoverable.
FOREIGN CURRENCY
The Company has significant operations outside of the United States, principally
in Russia and Venezuela. Both Russia and Venezuela are considered highly
inflationary economies and as a result, operations in those countries are
remeasured in United States dollars and any currency gains or losses are
recorded in the statement of income. The Company attempts to manage its
operations in a manner to reduce its exposure to foreign exchange losses;
however, there are many factors which affect foreign exchange rates and
resulting exchange gains and losses, many of which are beyond the influence of
the Company. The Company has recognized significant exchange gains and losses in
the past, resulting from fluctuations in the relationship of the Venezuelan and
Russian currencies to the United States dollar. It is not possible to predict
the extent to which the Company may be affected by future changes in exchange
rates.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist primarily of cash and cash
equivalents, accounts receivable and payable, marketable securities, short term
borrowings and debt instruments. In addition, in 1994 the Company entered into a
commodity hedge agreement (see Note 15). The book values of all financial
instruments, other than debt instruments, are representative of their fair
values due to their short term maturities. The book values of the Company's debt
instruments, except the convertible subordinated debentures and notes, are
considered to approximate their fair values because the interest rates of these
instruments are based on current rates offered to the Company. As discussed in
Note 3, all of the subordinated debentures and notes were either converted or
repaid in 1996. Based on the last trading sale price on December 31, 1995, the
convertible subordinated debentures had a fair value of approximately
$5,948,000. The fair value of the hedge agreement is the estimated
S-8
<PAGE> 37
amount the Company would have to pay to terminate the agreement, taking into
account current oil prices and the current creditworthiness of the hedge
counterparties. The estimated termination cost associated with the hedge
agreement at December 31, 1995 was approximately $834,000.
STOCK OPTIONS
Statement of Financial Accounting Standards No. 123 ("SFAS 123") regarding
accounting for stock-based compensation is effective for the Company beginning
January 1, 1996. SFAS 123 requires expanded disclosures of stock-based
compensation arrangements and encourages (but does not require) compensation
cost to be measured based on the fair value of the equity instrument awarded.
The Company will continue to apply APB Opinion No. 25 ("APB 25") to its stock
based compensation awards to employees and disclose the required pro forma
effect on net income and earnings per share (see Note 7).
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
RECLASSIFICATIONS
Certain items in 1995 and 1994 have been reclassified to conform to the 1996
financial statement presentation.
NOTE 2 - ACQUISITIONS AND SALES
In March 1994, the Company acquired capital stock from Vinccler representing an
additional 30% ownership interest in Benton-Vinccler for $3 million in cash, $10
million in non-interest bearing notes payable (with a present value of $9.2
million assuming a 10% interest rate) payable in various installments over 24
months and 200,000 shares of the Company's common stock. The excess of the
purchase price over the book value of the 30% interest was allocated to oil and
gas properties.
In November 1994, the Company sold a 10.8% working interest (24.9% of the
Company's 43.3% working interest) in the West Cote Blanche Bay Field for
approximately $5.8 million.
In March 1995, the Company sold its 32.5% working interest in certain depths
(above approximately 10,575 feet) in the West Cote Blanche Bay Field for
approximately $14.9 million. In April 1996, the Company sold its remaining
interests in the West Cote Blanche Bay, Rabbit Island and Belle Isle Fields
located in the Gulf Coast of Louisiana for approximately $35.4 million,
resulting in a gain of approximately $7.2 million after adjustments for revenues
and expenses subsequent to the effective date of December 31, 1995 and
satisfaction of a net profits interest associated with the properties. In
conjunction with this sale and to obtain the required consents for such sale,
the Company agreed to repay $35 million in senior unsecured notes and a $5
million revolving credit facility which was secured in part by these properties.
Debt prepayment premiums and related costs totaling approximately $11.0 million
($10.1 million net of tax benefits) were recognized as an extraordinary charge
in 1996 (see Note 3).
In January 1996, the Company completed an exchange offer under which it issued
an aggregate of 168,362 shares of common stock and warrants to purchase 587,783
shares of common stock at $11 per share in exchange for all outstanding limited
partnership interests in the three remaining limited partnerships sponsored by
the Company. The shares of common stock were valued at $1.9 million (based upon
the current market price at the time of the offer), which was allocated to oil
and gas properties. Substantially all of the oil and gas properties were
immediately sold at their approximate book value. The warrants, issued as an
inducement to the participants to accept the exchange offer, were valued at
$3.64 per warrant (an aggregate of $2.1 million), which was charged to expense
in 1996.
S-9
<PAGE> 38
In December 1996, the Company acquired Crestone Energy Corporation, a privately
held corporation headquartered in Denver, Colorado, for 628,142 shares of common
stock and options to purchase 107,571 shares of the Company's common stock at
$7.00 per share, valued at $14.6 million. Crestone's primary asset is a large
undeveloped acreage position in the South China Sea, under a petroleum contract
with China National Offshore Oil Corporation ("CNOOC") of the People's Republic
of China for an area known as Wan'An Bei, WAB-21. Crestone will, as a wholly
owned subsidiary of the Company, continue as the operator and contractor of
WAB-21.
NOTE 3 - LONG TERM DEBT
Long term debt consists of the following at December 31:
<TABLE>
<CAPTION>
1996 1995
-------------------- -------------
<S> <C> <C>
Senior unsecured notes with interest at 11.625%.
See description below. $125,000,000
Senior unsecured notes with interest at 13.0%.
See description below. $35,000,000
Revolving secured credit facility. Interest
payments due quarterly beginning
March 31, 1995. See description below. 5,000,000
Convertible subordinated debentures with
interest at 8.0%. See description below. 4,310,000
Convertible subordinated notes with interest
at 8.0%. See description below. 3,269,000
Benton-Vinccler credit facility with interest at
LIBOR plus 6%. Collateralized by a time deposit
of the Company earning approximately LIBOR plus 5.75%.
See description below. 50,000,000
Promissory note due on July 1, 1996 with
interest at 13.0% from January 1, 1996.
Unsecured. 1,000,000
Vendor financing with interest ranging from 10.5 to 13.5%.
Principal and interest payments due in varying
installments. Unsecured. 6,234,357
Bank financing with interest at LIBOR plus
7.5% to 8.0%. Secured by certain GEOILBENT
oil export proceeds. See description below. 1,105,000 850,000
Other--various equipment leases and bank financing with
interest and/or principal payments due monthly.
Interest rates vary from 9.75% to 16.91%. Notes and
leases mature from March 1997 to March 2000.
Secured by equipment and, at December 31, 1995,
residential real estate. 55,721 1,256,288
------------ -----------
176,160,721 56,919,645
Less current portion 1,132,516 7,433,339
------------ -----------
$175,028,205 $49,486,306
============ ===========
</TABLE>
In May 1996, the Company issued $125 million in 11.625% senior unsecured notes
due May 1, 2003. Interest on the notes is due May 1 and November 1 of each year,
beginning November 1, 1996. The indenture agreement provides for certain
limitations on liens, additional indebtedness, certain investment and capital
expenditures, dividends, mergers and sales of assets. At December 31, 1996, the
Company was in compliance with all covenants of the indenture. A portion of the
proceeds from the notes was used to repay certain long term indebtedness and
certain short term obligations, and the remainder has been or will be used for
capital expenditure and working capital purposes.
In August 1996, Benton-Vinccler entered into a $50 million, 2-year credit
facility with Morgan Guaranty Trust Company of New York ("Morgan Guaranty") to
repay the balance outstanding under a short term credit facility (see Note 4)
and to repay certain advances received from the Company. The credit facility is
collateralized in full by a time deposit of the Company and bears interest at
LIBOR plus 6%. The Company will receive interest on its time deposit and a
security fee on the outstanding principal of the loan, for a combined total of
approximately LIBOR plus 5.75%. The loan arrangement contains no restrictive
covenants and no financial ratio covenants.
S-10
<PAGE> 39
In September 1994 and June 1995, the Company issued $15 million and $20 million
in 13% senior unsecured notes due 2002 and 2007, respectively. Additionally, in
connection with the two issuances of notes, the Company issued warrants
entitling the holder to purchase 250,000 shares of common stock at $9.00 per
share and 125,000 shares at $17.09 per share, subject to adjustment in certain
circumstances, that are exercisable on or before September 30, 2002 and June 30,
2007, respectively. In April and May 1996, in conjunction with the sale of the
Company's Gulf Coast properties and the issuance of $125 million of debt, the
Company repaid the outstanding 13% notes, accrued interest, and corresponding
prepayment premiums of $11.0 million (see Note 2).
In December 1994, the Company entered into a $10 million revolving credit
facility, secured in part by mortgages on the Company's U.S. properties and in
part by a guarantee provided by the financial institution which arranged the
credit facility. In exchange for the credit enhancement, the Company issued to
the arranging financial institution and lending commercial bank warrants
entitling the holders to purchase 50,000 shares of common stock at $12.00 per
share, subject to adjustment in certain circumstances, that are exercisable on
or before December 2004, and the Company granted to the arranging institution a
5% net profits interest in the Company's properties whose development was
financed by the facility. In conjunction with the sale of the Company's Gulf
Coast properties in April 1996, the Company repaid the outstanding balance of
$5.0 million to the lending institution (see Note 2).
In May 1992, the Company issued $6.4 million aggregate principal amount of
publicly offered 8% convertible subordinated debentures due May 1, 2002,
convertible at the option of the note holders at 101.157 shares per $1,000
principal amount. In May 1996, the holders of the outstanding notes were
notified of the Company's intention to prepay the debentures on July 23, 1996 at
103% of the principal amount plus accrued interest. As a result, holders of the
remaining debentures elected to convert their debentures for shares of common
stock. During 1996, the Company issued 435,872 shares of common stock upon the
conversion of debentures with a principal amount of $4.3 million.
In October 1991, the Company issued $4.7 million aggregate principal amount of
privately placed 8% convertible subordinated notes due October 1, 2001,
convertible at the option of the note holders at 85.259 shares per $1,000
principal amount. In December 1995, the holders of the outstanding notes were
notified of the Company's intention to prepay the notes on February 12, 1996 at
103% of the principal amount plus accrued interest. As a result, substantially
all of the holders elected to convert their notes for shares of common stock.
During 1996, the Company issued 275,081 shares of common stock upon the
conversion of notes with a principal amount of $3.2 million.
Beginning in August 1994, GEOILBENT had entered into various agreements with
International Moscow Bank ("IMB") for credit facilities with the following
terms: amounts of $4-6 million, repayment over 14 to 17 months, and interest at
LIBOR plus 7.5 to 8.0%. In December 1995, GEOILBENT signed a new credit facility
with IMB for $5 million, payable over 17 months with interest at LIBOR plus
8.0%. At December 31, 1996 and 1995, the Company's proportionate share of the
outstanding balances was $1.1 million and $0.9 million, respectively. While the
repayment of loans under earlier agreements was guaranteed by the Company,
repayment under the current agreement is not.
The principal requirements for the long term debt outstanding at December 31,
1996 are due as follows for the years ending December 31:
<TABLE>
<S> <C>
1997 $ 1,132,516
1998 50,012,286
1999 13,550
2000 2,369
2001 -
Subsequent Years 125,000,000
------------
$176,160,721
============
</TABLE>
S-11
<PAGE> 40
NOTE 4 - SHORT TERM BORROWINGS
In 1994, Benton-Vinccler entered into a $25 million credit facility with Morgan
Guaranty to repay commercial paper and for working capital requirements. The
credit facility was collateralized in full by time deposits from the Company,
bore interest at LIBOR plus 3/4% and was renewed on a monthly basis. The loan
arrangement contained no restrictive covenants and no financial ratio covenants.
The outstanding balance under the credit facility at December 31, 1995 was
$19.25 million. In August 1996, the facility was replaced by a long term
agreement for $50 million (see Note 3).
Beginning in the fourth quarter of 1994, Benton-Vinccler acquired approximately
$4.1 million of drilling and production equipment from trading companies and
suppliers under terms which included repayment within a 12-month period in
monthly and quarterly installments at interest rates from 6.7% to 10.75%. At
December 31, 1995, approximately $0.7 million related to these loans was
outstanding. In June 1996, the Company paid the balance remaining on these
purchases with proceeds from its debt issuance in May 1996 (see Note 3).
In June 1994, GEOILBENT entered into a payment advance agreement with NAFTA
Moscow, the export agency which markets GEOILBENT's oil production to purchasers
in Europe. The payment advance of $2.5 million against future oil shipments,
which bore an effective discount rate of 12%, was repaid through withholdings
from oil sales on a monthly basis through December 1994. In March and August
1995, GEOILBENT received $3.0 million and $2.0 million, respectively, in
production payment advances pursuant to similar agreements with NAFTA Moscow
containing similar terms. During the period ended September 30, 1996, GEOILBENT
repaid the original NAFTA Moscow advances. Funding for the repayment was
provided largely by entering into other oil payment advance arrangements and
similar short term borrowings with other oil purchasers and with Russian
commercial banks. GEOILBENT also entered into an agreement with Morgan Guaranty
for a short term credit facility under which the Company provides cash
collateral for the loans to GEOILBENT. GEOILBENT's obligations under the new
agreements with the Russian commercial banks and oil purchaser are not
guaranteed by the Company. At December 31, 1996, the Company's proportionate
share of the outstanding short term borrowings of GEOILBENT was $0.9 million.
NOTE 5 - COMMITMENTS AND CONTINGENCIES
In May 1996, the Company entered into an agreement with Morgan Guaranty which
provides for a $20 million revolving credit facility and an $18 million cash
collateralized 5-year letter of credit to secure the Company's performance of
the minimum exploration work program required in the Delta Centro Block in
Venezuela. The revolving credit facility could be drawn upon until December 1996
with interest at LIBOR plus 3% through June 1997 and LIBOR plus 3.75%
thereafter. Any amount outstanding at the end of the revolving period will
automatically convert into a term loan due 15 months thereafter. The credit
facility contains financial covenants requiring that the Company maintain a
current ratio of at least 1.1 to 1.0 and a minimum net worth of $100 million at
the end of each fiscal quarter. No amounts were drawn under the credit facility
in 1996 and the commitment period has expired.
Investors in partnerships which were sponsored by a third party have sued the
Company on the theory that since it provided oil and gas drilling prospects to
those partnerships and operated substantially all of their properties, it was
responsible for alleged violations of securities laws in connection with the
offer and sale of interests, contractual breach of fiduciary duty and fraud. The
Company has entered into a settlement agreement related to these claims, whereby
the Company has paid $990,000 to the plaintiffs in full settlement of these
claims. Legal fees of $683,272 in addition to the settlement amount have been
included in litigation settlement expenses for the year ended December 31, 1995.
In the normal course of its business, the Company may periodically become
subject to actions threatened or brought by its investors or partners in
connection with the operation or development of its properties or the sale of
securities. Prior to 1992, the Company was engaged in the formation and
operation of oil and gas limited partnership interests. In 1992, the Company
ceased raising funds through such sales. Certain limited partners in limited
partnerships sponsored by the Company have brought an action against the Company
in connection with the
S-12
<PAGE> 41
Company's operation of the limited partnerships as managing general partner. The
plaintiffs seek actual and punitive damages for alleged actions and omissions by
the Company in operating the partnerships and alleged misrepresentations made by
the Company in selling the limited partnership interests. In May 1995, the
Company agreed to a binding arbitration proceeding with respect to such claims.
As of September 30, 1996, the plaintiffs had not commenced discovery. The
Company intends to vigorously defend this action and does not believe the claims
raised are meritorious. However, new developments could alter this conclusion at
any time. The Company will be forced to expend time and financial resources to
defend or resolve any such matters. The Company is also subject to ordinary
litigation that is incidental to its business. None of the above matters are
expected to have a material adverse effect on the Company's financial
statements.
The Company's aggregate rental commitments for noncancellable agreements at
December 31, 1996, are as follows:
<TABLE>
<CAPTION>
Rental Commitments
------------------
<S> <C>
1997 $ 363,320
1998 337,741
1999 334,461
2000 328,784
2001 323,794
Thereafter 925,956
--------------
$ 2,614,056
==============
</TABLE>
Rental expense was $2,232,686, $1,981,253 and $ 255,650 for the years ended
December 31, 1996, 1995 and 1994, respectively.
NOTE 6 - TAXES ON INCOME
The tax effects of significant items comprising the Company's net United States
deferred income taxes as of December 31, 1996 and 1995 are as follows:
<TABLE>
<CAPTION>
1996 1995
------------ ------------
<S> <C> <C>
Deferred tax assets:
Operating loss carryforwards $ 26,100,000 $ 16,400,000
Other 1,200,000
Valuation allowance (19,900,000) (12,900,000)
------------ ------------
Total 7,400,000 3,500,000
------------ ------------
Deferred tax liabilities:
Difference in basis of property 7,400,000 3,500,000
Other -- --
------------ ------------
Total 7,400,000 3,500,000
------------ ------------
Net deferred tax liability $ -- $ --
============ ============
</TABLE>
The components of income before income taxes and minority interest are as
follows:
<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Income (loss) before income taxes:
United States $ 3,063,000 $ (9,500,000) $ (4,363,000)
Foreign 65,787,000 27,873,000 10,109,000
----------- ------------ ------------
Total $68,850,000 $ 18,373,000 $ 5,746,000
=========== ============ ============
</TABLE>
S-13
<PAGE> 42
The provision for income taxes for the year ended December 31, 1996, consists
primarily of $3.8 million of foreign taxes currently payable and $16.7 million
of foreign deferred taxes, with the deferred taxes relating primarily to
property basis differences. The provision for income taxes for the years ended
December 31, 1995 and 1994 consists primarily of foreign income taxes currently
payable. A comparison of the income tax expense at the federal statutory rate to
the Company's provision for income taxes is as follows:
<TABLE>
<CAPTION>
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
Computed tax expense at the statutory rate $24,097,000 $6,431,000 $2,011,000
State income taxes, net of federal effect 1,249,000 919,000 287,000
Rate differential for foreign income (4,800,000) (7,278,000) (2,853,000)
Other (632,000) (1,689,000) (552,000)
Change in valuation allowance 595,000 4,095,000 1,805,000
----------- ---------- ----------
Provision for income taxes $20,509,000 $2,478,000 $ 698,000
=========== ========== ==========
</TABLE>
At December 31, 1996, the Company had, for federal income tax purposes,
operating loss carryforwards of approximately $71 million, expiring in the years
2003 through 2011. If the carryforwards are ultimately realized, approximately
$9 million will be credited to additional paid-in capital for tax benefits
associated with deductions for income tax purposes related to stock options.
The Company has not provided for United States income taxes on $65 million of
foreign subsidiaries' unremitted earnings at December 31, 1996 which are
expected to be reinvested indefinitely. It is not practicable to determine the
amount of income taxes that might be payable if such earnings are ultimately
repatriated.
NOTE 7 - STOCK OPTIONS
The Company adopted its 1988 Stock Option Plan in December 1988 authorizing
options to acquire up to 418,824 shares of common stock. Under the plan,
incentive stock options ("ISOs") were granted to a key employee and other
non-qualified stock options (NQSOs"), stock or bonus rights were granted to
other key employees, directors, independent contractors and consultants at
prices equal to or below market price, exercisable over various periods. The
remaining options to purchase 80,000 shares of common stock for $4.89 per share
were exercised during 1995. During 1989, the Company adopted its 1989
Nonstatutory Stock Option Plan covering 2,000,000 shares of common stock which
were granted to key employees, directors, independent contractors and
consultants at prices equal to or below market prices, exercisable over various
periods. The plan was amended during 1990 to add 1,960,000 shares of common
stock to the plan.
In September 1991, the Company adopted the 1991-1992 Stock Option Plan and the
Directors' Stock Option Plan. The 1991-1992 Stock Option Plan, as amended in
1996, permits the granting of stock options to purchase up to 3,400,000 shares
of the Company's common stock in the form of ISOs and NQSOs to officers and
employees of the Company. Options may be granted as ISOs, NQSOs or a combination
of each, with exercise prices not less than the fair market value of the common
stock on the date of the grant. The amount of ISOs that may be granted to any
one participant is subject to the dollar limitations imposed by the Internal
Revenue Code of 1986, as amended. In the event of a change in control of the
Company, all outstanding options become immediately exercisable to the extent
permitted by the 1991-1992 Stock Option Plan. All options granted to date under
the 1991-1992 Stock Option Plan vest ratably over a three-year period from their
dates of grant and expire ten years from grant date or one year after
retirement, if earlier.
The Directors' Stock Option Plan permits the granting of nonqualified stock
options ("Director NQSOs") to purchase up to 400,000 shares of common stock to
nonemployee directors of the Company. Upon election as a director and annually
thereafter, each individual who serves as a nonemployee director automatically
is granted an option to purchase 10,000 shares of common stock at a price not
less than the fair market value of common stock on the date of grant. All
Director NQSOs vest automatically on the date of the grant of the options and at
December 31, 1996, options to purchase 224,000 shares of common stock were both
outstanding and exercisable.
S-14
<PAGE> 43
A summary of the status of the Company's stock option plans as of December 31,
1996, 1995 and 1994 and changes during the years ending on those dates is
presented below:
<TABLE>
<CAPTION>
1996 1995 1994
-------------------- --------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
PRICE SHARES PRICE SHARES PRICE SHARES
----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of the year: $ 8.04 3,341,820 $ 6.74 3,033,567 $ 6.52 2,194,567
Options granted 19.33 657,500 13.86 557,500 7.26 865,000
Options exercised 6.69 (886,134) 4.92 (192,580) 3.72 (23,000)
Options canceled 12.14 (76,667) 6.53 (56,667) 10.13 (3,000)
--------- --------- ---------
Outstanding at end of the year 10.78 3,036,519 8.04 3,341,820 6.74 3,033,567
========= ========= =========
Exercisable at end of the year 7.90 1,887,349 6.76 2,209,322 6.27 1,831,901
========= ========= =========
</TABLE>
Significant option groups outstanding at December 31, 1996 and related weighted
average price and life information follow:
<TABLE>
<CAPTION>
NUMBER OUTSTANDING WEIGHTED=AVERAGE WEIGHTED= NUMBER WEIGHTED-
RANGE OF EXERCISE AT REMAINING AVERAGE EXERCISE EXERCISABLE AT AVERAGE
PRICES DECEMBER 31, 1996 CONTRACTUAL LIFE PRICE DECEMBER 31, 1996 EXERCISE PRICE
- ----------------- ------------------- ----------------- ---------------- ----------------- --------------
<S> <C> <C> <C> <C> <C>
$1.39 40,000 7.8 Years $1.39 40,000 $1.39
2.39 81,667 8.2 Years 2.39 81,667 2.39
4.89 - 7.00 817,166 7.4 Years 5.54 678,831 5.46
7.50 - 10.88 1,012,853 7.2 Years 8.93 881,184 8.89
11.50 - 15.25 637,333 8.1 Years 14.50 175,667 14.08
17.88 - 24.13 447,500 8.3 Years 21.59 30,000 21.88
--------- ---------
3,036,519 1,887,349
========= =========
</TABLE>
The weighted average fair value of the stock options granted from the 1991-1992
Stock Option Plan and the Directors' Stock Option Plan during 1996 and 1995 was
$13.10 and $8.92, respectively. The fair value of each stock option grant is
estimated on the date of grant using the Black-Scholes option pricing model with
the following weighted average assumptions used:
<TABLE>
<CAPTION>
1996 1995
---------- -------
<S> <C> <C>
Expected life 8.6 years 7.5 years
Risk-free interest rate 6.2% 6.0%
Volatility 54% 54%
Dividend yield 0% 0%
</TABLE>
The Company accounts for stock-based compensation in accordance with APB 25,
under which no compensation cost has been recognized for stock option awards.
Had compensation cost for the plans been determined consistent with SFAS 123,
the Company's pro forma net income and earnings per share for 1996 and 1995
would have been as follows:
<TABLE>
<CAPTION>
1996 1995
----------- -----------
<S> <C> <C>
Net income:
Income before extraordinary charge $36,082,673 $10,368,674
Extraordinary charge 10,074,799
------------ ------------
Net income $26,007,874 $10,368,674
=========== ===========
Net income per common share:
Primary:
Income before extraordinary charge $ 1.23 $ 0.39
Extraordinary charge 0.34
------------ -----------
Net income $ 0.89 $ 0.39
============ ===========
</TABLE>
S-15
<PAGE> 44
<TABLE>
<CAPTION>
1996 1995
----------- -----------
<S> <C> <C>
Fully diluted:
Primary:
Income before extraordinary charge $ 1.20 $ 0.38
Extraordinary charge 0.33
----------- -----------
Net income $ 0.87 $ 0.38
=========== ===========
</TABLE>
Because options vest over several years and additional options are granted each
year, the effects on pro forma net income and related per share amounts
presented above are not representative of the effects for future years.
In addition to options issued pursuant to the plans, options for 65,000 and
30,000 shares of common stock were issued in 1995 and 1994, respectively, to
individuals other than officers, directors or employees of the Company at prices
ranging from $5.63 to $10.88. These options vest over three to four years and at
December 31, 1996, 246,500 options were outstanding, 155,667 of which were
vested.
NOTE 8 - STOCK WARRANTS
During the years ended December 31, 1994, 1995 and 1996, the Company issued a
total 450,000, 125,000 and 587,783 warrants, respectively. Each warrant entitles
the holder to purchase one share of common stock at the exercise price of the
warrant. Substantially all the warrants are immediately exercisable upon
issuance.
In January 1992, 29,841 warrants were issued to a placement agent who sold
shares in a public offering of the Company's stock, 6,220 of which were
exercised during the year ended December 31, 1996. In February 1992, 37,118
warrants were issued in connection with the marketing of working interests in a
well the Company drilled, 155 and 4,905 of which were exercised during the years
ended December 31, 1995 and 1996, respectively. Also in February 1992, 25,000
warrants were issued in connection with an acquisition of a working interest in
a well. In April 1992, 31,400 warrants were issued to a placement agent who
marketed the Company's 8% convertible subordinated debentures, 1,000 of which
were exercised during the year ended December 31, 1996. In July 1992, 5,000
warrants were issued to a consultant to the Company, 2,500, 1,000 and 1,500 of
which were exercised during the years ended December 31, 1993, 1995 and 1996,
respectively. In October 1992, 527,000 warrants were issued to the partners of
two limited partnerships managed by the Company that were liquidated in November
1992, 2,000 and 210,000 of which were exercised during the years ended December
31, 1995 and 1996, respectively.
In September 1994, 250,000 warrants were issued in connection with the issuance
of $15 million in senior unsecured notes, and in December 1994, 50,000 warrants
were issued in connection with a revolving secured credit facility. In July
1994, the Company issued warrants entitling the holder to purchase a total of
150,000 shares of common stock at $7.50 per share, subject to adjustment in
certain circumstances, that are exercisable on or before July 2004. 50,000
warrants were immediately exercisable, and 50,000 warrants became exercisable
each July in 1995 and 1996. During the year ended December 31, 1996, 142,000 of
these warrants were exercised.
In June 1995, 125,000 warrants were issued in connection with the issuance of
$20 million in senior unsecured notes.
In January 1996, 587,783 warrants were issued in connection with an exchange
offer under which the Company acquired the outstanding limited partnership
interests in three limited partnerships sponsored by the Company (see Note 2).
During the year ended December 31, 1996, 9,215 of the warrants were exercised.
S-16
<PAGE> 45
The dates the warrants were issued, the expiration dates, the exercise prices
and the number of warrants issued and outstanding at December 31, 1996 were:
<TABLE>
<CAPTION>
DATE ISSUED EXPIRATION DATE EXERCISE PRICE ISSUED OUTSTANDING
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
January 1992 January 1997 $12.03 29,841 23,621
February 1992 February 1997 14.63* 37,118 32,058
February 1992 February 1997 9.00 25,000 25,000
April 1992 April 1997 10.30 31,400 30,400
October 1992 October 1997 10.00 527,000 315,000
July 1994 July 2004 7.50 150,000 8,000
September 1994 September 2002 9.00 250,000 250,000
December 1994 December 2004 12.00 50,000 50,000
June 1995 June 2007 17.09 125,000 125,000
January 1996 January 1999 11.00 587,783 578,568
--------- ---------
1,813,142 1,437,647
========= =========
<FN>
* Price represents weighted average price.
</TABLE>
NOTE 9 - RUSSIAN EXPORT TARIFF
For the year ended December 31, 1994 and the period January 1 through June 30,
1996, the Company recorded an expense for the Russian export tariff of
$1,397,317 and $845,385, respectively, which is included in lease operating
expenses and production taxes. GEOILBENT received a waiver from the export
tariff for 1995 and in July 1996, such oil export tariffs were terminated in
conjunction with a loan agreement with the International Monetary Fund. Excise,
pipeline and other taxes continue to be levied on all oil producers and certain
exporters. The Russian regulatory environment continues to be volatile and the
Company is unable to predict the impact of taxes, duties and other burdens for
the future.
NOTE 10 - VENEZUELA OPERATIONS
On July 31, 1992, the Company and its partner, Venezolana de Inversiones y
Construcciones Clerico, C.A. ("Vinccler"), signed an operating service agreement
to reactivate and further develop three Venezuelan oil fields with Lagoven,
S.A., an affiliate of the national oil company, Petroleos de Venezuela, S.A
("PDVSA"). The operating service agreement covers the Uracoa, Bombal and
Tucupita fields that comprise the South Monagas Unit ("Unit"). Under the terms
of the operating service agreement, Benton-Vinccler, a corporation owned 80% by
the Company and 20% by Vinccler, is a contractor for Lagoven and is responsible
for overall operations of the South Monagas Unit, including all necessary
investments to reactivate and develop the fields comprising the Unit.
Benton-Vinccler receives an operating fee in U.S. dollars deposited into a U.S.
commercial bank account for each barrel of crude oil produced (subject to
periodic adjustments to reflect changes in a special energy index of the U.S.
Consumer Price Index) and is reimbursed according to a prescribed formula in
U.S. dollars for its capital costs, provided that such operating fee and cost
recovery fee cannot exceed the maximum dollar amount per barrel set forth in the
agreement (which amount is periodically adjusted to reflect changes in the
average of certain world crude oil prices). The Venezuelan government maintains
full ownership of all hydrocarbons in the fields.
In January 1996, the Company and its bidding partners, Louisiana Land &
Exploration ("LL&E") and Norcen Energy Resources, LTD ("Norcen") were awarded
the right to explore and develop the Delta Centro Block in Venezuela. The
contract requires a minimum exploration work program consisting of completing a
1,300 kilometer seismic survey and drilling three wells to depths of 12,000 to
18,000 feet within five years. PDVSA estimates that this minimum exploration
work program will cost $60 million and requires that the Company, LL&E and
Norcen each post a performance surety bond or standby letter of credit for its
pro rata share of the estimated work commitment expenditures. The Company has a
30% interest in the exploration venture, with LL&E and Norcen each owning a 35%
interest. Under the terms of the operating agreement, which establishes the
management company of the project, LL&E will be the operator of the field and,
therefore, the Company will not be able to exercise control of the
S-17
<PAGE> 46
operations of the venture. Corporation Venezolana del Petroleo, S.A., an
affiliate of PDVSA, has a 35% interest in the management company, which dilutes
the voting power of the partners on a pro rata basis. In July 1996, formal
agreements were finalized and executed and the Company posted an $18 million
standby letter of credit, which is collateralized in full by a time deposit of
the Company, to secure its 30% share of the minimum exploration work program.
NOTE 11 - CHINA
In December 1996, the Company acquired Crestone Energy Corporation, a privately
held corporation headquartered in Denver, Colorado, for 628,142 shares of common
stock and options to purchase 107,571 shares of the Company's common stock at
$7.00 per share, valued at $14.6 million. Crestone's primary asset is a large
undeveloped acreage position in the South China Sea, under a petroleum contract
with China National Offshore Oil Corporation ("CNOOC") of the People's Republic
of China for an area known as Wan'An Bei, WAB-21. Crestone will, as a wholly
owned subsidiary of the Company, continue as the operator and contractor of
WAB-21. Crestone has submitted an exploration program and budget to CNOOC for
1997. However, due to certain territorial disputes over the sovereignty of the
contract area, it is unclear when such program will commence.
NOTE 12 - RELATED PARTY TRANSACTIONS
On December 31, 1993, the Company guaranteed a loan made to Mr. A.E. Benton, its
Chief Executive Officer for $300,000. In January 1994, the Company loaned
$800,000 to Mr. Benton with interest at prime plus 1%; in September 1994, Mr.
Benton made a payment of $207,014 against this loan. In December 1995, the
Company purchased a home from Mr. Benton for $1.73 million, based on independent
appraisals, and from the proceeds Mr. Benton repaid the balance owed to the
Company of $592,986 plus accrued interest and the $300,000 loan guaranteed by
the Company. The home, which the Company sold for $1.5 million in 1996, has been
included in other assets as of December 31, 1995. During 1996, the Company
loaned $268,154 to Mr. Benton, and $600,000 to Mr. M.B. Wray, its President and
Chief Financial Officer, each loan bearing interest at 6%.
NOTE 13 - EARNINGS PER SHARE
Primary earnings per common share are computed by dividing net income (loss) by
the weighted average number of common and common equivalent shares outstanding.
Common equivalent shares are shares which may be issuable upon exercise of
outstanding stock options and warrants. Total weighted average common stock
equivalent shares used to calculate earnings per common share were:
<TABLE>
<CAPTION>
1996 1995 1994
----- ----- ----
<S> <C> <C> <C>
Primary shares 29,590,359 26,673,483 25,314,026
Fully diluted shares 30,414,693 27,289,343 25,416,792
</TABLE>
In February 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128 ("SFAS 128") "Earnings per Share." SFAS
128 replaces the presentation of primary earnings per share with a presentation
of basic earnings per share based upon the weighted average number of common
shares for the period. It also requires dual presentation of basic and diluted
earnings per share for companies with complex capital structures. SFAS 128 will
be adopted by the Company in the first quarter of 1997 and earnings per share
for all prior periods will be restated upon adoption.
NOTE 14 - MAJOR CUSTOMERS
The Company is principally involved in the business of oil and gas exploration
and production. Oil and gas purchasers which represented more than 10% of oil
and gas revenues were Lagoven, S.A. (93% and 79%) for the years ended December
31, 1996 and 1995, respectively, and Lagoven, S.A. (67%) and Texon Corporation
(10%) for the year ended December 31, 1994.
S-18
<PAGE> 47
NOTE 15 - OIL AND GAS ACTIVITIES
Total costs incurred in oil and gas acquisition, exploration and development
activities were:
<TABLE>
<CAPTION>
UNITED STATES
AND
VENEZUELA RUSSIA CHINA OTHER TOTAL
--------- ------ ----- ----- -----
<S> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1996
Property acquisition costs $15,105,597 $1,139,494 $ 16,245,091
Development costs $ 82,196,624 $ 6,047,234 1,498,460 89,742,318
Exploration costs 1,392,907 279,446 714,759 2,387,112
------------ ------------- ----------- ---------- ------------
$ 83,589,531 $ 6,047,234 $15,385,043 $3,352,713 $108,374,521
============ ============= =========== ========== ============
YEAR ENDED DECEMBER 31, 1995
Property acquisition costs $ 435,575 $ 435,575
Development costs $ 54,533,329 $ 12,373,856 5,463,239 72,370,424
Exploration costs 112,054 593,367 705,421
------------ ------------- ---------- ------------
$ 54,645,383 $ 12,373,856 $6,492,181 $ 73,511,420
============ ============= ========== ============
YEAR ENDED DECEMBER 31, 1994
Property acquisition costs $ 13,446,757 $ 875,129 $ 14,321,886
Development costs 24,676,748 $ 8,654,730 2,993,728 36,325,206
Exploration costs 265,856 2,542,935 2,808,791
------------ ------------- ---------- ------------
$ 38,389,361 $ 8,654,730 $6,411,792 $ 53,455,883
============ ============= ========== ============
</TABLE>
The Company's aggregate amount of capitalized costs related to oil and gas
producing activities consists of the following at December 31:
<TABLE>
<CAPTION>
UNITED STATES
AND
VENEZUELA RUSSIA CHINA OTHER TOTAL
--------- ------ ----- ----- -----
<S> <C> <C> <C> <C> <C>
DECEMBER 31, 1996
Proved property costs $182,566,405 $ 45,522,896 $228,089,301
Costs excluded from amortization 8,935,183 809,204 $15,385,043 $ 857,551 25,986,981
Oilfield inventories 5,545,499 5,545,499
Less accumulated depletion (46,143,370) (5,197,150) (51,340,520)
------------ ------------ ----------- ----------- ------------
$150,903,717 $ 41,134,950 $15,385,043 $ 857,551 $208,281,261
============ ============ =========== =========== ============
DECEMBER 31, 1995
Proved property costs $ 93,910,671 $ 37,070,018 $130,980,689
Costs excluded from amortization 14,001,386 3,214,849 $ 709,136 17,925,371
Properties held for sale (net of accumulated
depletion of $8,344,830) 22,885,176 22,885,176
Oilfield inventories 5,306,735 12,579 5,319,314
Less accumulated depletion (16,620,070) (2,449,846) (19,069,916)
------------ ------------ ------------ ------------
$ 96,598,722 $ 37,835,021 $ 23,606,891 $158,040,634
============ ============ ============ ============
DECEMBER 31, 1994
Proved property costs $ 46,523,663 $ 25,482,193 $ 27,508,414 $ 99,514,270
Costs excluded from amortization 6,743,012 2,428,818 7,523,454 16,695,284
Oilfield inventories 1,228,225 16,385 1,244,610
Less accumulated depletion (5,227,293) (937,025) (13,278,505) (19,442,823)
------------ ------------ ------------ ------------
$ 49,267,607 $ 26,973,986 $ 21,769,748 $ 98,011,341
============ ============ ============ ============
</TABLE>
The Company regularly evaluates its unproved properties to determine whether
impairment has occurred. The Company has excluded from amortization its interest
in unproved properties, the cost of uncompleted exploratory activities, and
portions of major development costs. The principal portion of such costs are
expected to be included in amortizable costs during the next two years.
S-19
<PAGE> 48
Excluded costs at December 31, 1996 consisted of the following by year incurred:
<TABLE>
<CAPTION>
TOTAL 1996 1995 1994 PRIOR TO 1994
----------- ----------- ---------- -------- -------------
<S> <C> <C> <C> <C> <C>
Property acquisition costs $15,136,098 $15,136,098
Development costs 7,395,209 $7,345,220 $ 49,989
Exploration costs 3,455,674 2,038,568 466,474 328,763 $621,869
----------- ----------- ---------- -------- --------
$25,986,981 $17,174,666 $7,811,694 $378,752 $621,869
=========== =========== ========== ======== ========
</TABLE>
Results of operations for oil and gas producing activities were:
<TABLE>
<CAPTION>
VENEZUELA RUSSIA UNITED STATES TOTAL
--------- ------ ------------- -----
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1996
Oil and gas revenues $136,839,863 $ 9,047,352 $4,675,484 $150,562,699
Expenses:
Lease operating costs and production taxes 17,669,377 6,263,034 585,152 24,517,563
Depletion 29,523,300 2,747,304 1,704,940 33,975,544
------------- ------------ ------------ ------------
Total expenses 47,192,677 9,010,338 2,290,392 58,493,592
Results of operations from oil and gas ------------- ------------ ------------ ------------
producing activities $ 89,647,186 $ 37,014 $2,385,392 $ 92,069,592
============= ============= ============ =============
YEAR ENDED DECEMBER 31, 1995
Oil and gas revenues $ 49,173,832 $ 6,016,297 $7,682,768 $ 62,872,897
Expenses:
Lease operating costs and production taxes 6,482,775 2,763,860 1,456,162 10,702,797
Depletion 11,392,777 1,512,821 4,187,440 17,093,038
------------ ------------ ----------- ------------
Total expenses 17,875,552 4,276,681 5,643,602 27,795,835
Results of operations from oil and gas ------------ ------------ ----------- ------------
producing activities $ 31,298,280 $ 1,739,616 $2,039,166 $ 35,077,062
============ =========== =========== ============
YEAR ENDED DECEMBER 31, 1994
Oil and gas revenues $ 21,472,015 $ 3,512,940 $7,286,723 $ 32,271,678
Expenses:
Lease operating costs and production taxes 3,807,434 2,832,621 2,891,209 9,531,264
Depletion 4,998,213 837,818 4,247,303 10,083,334
------------ ------------ ------------ ------------
Total expenses 8,805,647 3,670,439 7,138,512 19,614,598
Results of operations from oil and gas ------------ ------------ ------------ ------------
producing activities $ 12,666,368 $ (157,499) $ 148,211 $ 12,657,080
============ ============= ============ ============
</TABLE>
Results of operations for oil and gas producing activities in Russia for 1995
reflect the nine months ended September 30, 1995 (see Note 1). Oil and gas
revenues and expenses in Russia for the quarter ended December 31, 1995 of $2.4
million and $2.0 million, respectively, have been included in the Company's
consolidated results of operations for 1996.
In May 1994, the Company entered into a commodity hedge agreement designed to
reduce a portion of the Company's risk from oil price movements through December
31, 1996. Pursuant to the hedge agreement, the Company received $16.82 per Bbl
and paid the average price per Bbl of West Texas Intermediate Light Sweet Crude
Oil. Such terms applied to production of 1,000 Bbl of oil per day for 1994,
1,250 Bbl of oil per day in 1995 and 1,500 Bbl of oil per day for 1996. During
the years ended December 31, 1996, 1995 and 1994, respectively, the Company
incurred losses of $2,859,278, $716,203 and $328,868, respectively, under the
hedge agreement which reduced oil and gas sales.
S-20
<PAGE> 49
QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED)
Proved reserves are estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected to
be recovered through existing wells with existing equipment and operating
methods. All Venezuelan reserves are attributable to an operating service
agreement between Benton-Vinccler and Lagoven, S.A., under which all mineral
rights are owned by the government of Venezuela. Sales of reserves in place in
1994 and 1995 include reserves related to the United States properties sold in
March 1995 and in April 1996 (see Note 2), respectively.
The evaluations of the oil and gas reserves as of December 31, 1996, 1995, 1994
and 1993 were audited by Huddleston & Co., Inc., independent petroleum
engineers.
<TABLE>
<CAPTION>
MINORITY
UNITED INTEREST
VENEZUELA RUSSIA STATES TOTAL IN VENEZUELA NET TOTAL
------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
PROVED RESERVES - CRUDE OIL, CONDENSATE,
AND GAS LIQUIDS (MBBLS)
YEAR ENDED DECEMBER 31, 1996
Proved reserves beginning of the year 73,593 22,618 96,211 (14,718) 81,493
Revisions of previous estimates (10,951) 712 (10,239) 2,190 (8,049)
Extensions, discoveries and
improved recovery 36,082 979 37,061 (7,216) 29,845
Production (12,648) (765) (13,413) 2,529 (10,884)
------- ------ ------- ------- --------
Proved reserves end of year 86,076 23,544 109,620 (17,215) 92,405
======= ====== ======= ======= ========
YEAR ENDED DECEMBER 31, 1995
Proved reserves beginning of the year 60,707 17,540 233 78,480 (12,141) 66,339
Revisions of previous estimates (12,877) (107) (12,984) 2,575 (10,409)
Extensions, discoveries and
improved recovery 31,219 5,569 91 36,879 (6,243) 30,636
Production (5,456) (491) (69) (6,016) 1,091 (4,925)
Sales of reserves in place (148) (148) (148)
------- ------ ------- ------- ------- --------
Proved reserves end of year 73,593 22,618 0 96,211 (14,718) 81,493
======= ====== ======= ======= ======= ========
YEAR ENDED DECEMBER 31, 1994
Proved reserves beginning of the year 19,389 10,121 10,258 39,768 39,768
Revisions of previous estimates (2,583) (201) 1,819 (965) 517 (448)
Purchases of reserves in place 19,389 19,389 (7,756) 11,633
Extensions, discoveries and
improved recovery 27,032 7,914 152 35,098 (5,406) 29,692
Production (2,520) (294) (226) (3,040) 504 (2,536)
Sales of reserves in place (11,770) (11,770) (11,770)
------- ------ ------- ------- ------- --------
Proved reserves end of year 60,707 17,540 233 78,480 (12,141) 66,339
======= ====== ======= ======= ======= ========
PROVED DEVELOPED RESERVES AT:
December 31, 1996 47,805 3,417 0 51,222 (9,561) 41,661
December 31, 1995 30,032 3,475 0 33,507 (6,006) 27,501
December 31, 1994 12,580 2,772 155 15,507 (2,516) 12,991
January 1, 1994 3,999 400 8,153 12,552 12,552
PROVED RESERVES - NATURAL GAS (MMCF)
YEAR ENDED DECEMBER 31, 1996
Proved reserves beginning of the year 6 6 6
Production (1) (1) (1)
Sales of reserves in place (5) (5) (5)
------- ------- -------
Proved reserves end of year 0 0 0
======= ======= =======
YEAR ENDED DECEMBER 31, 1995
Proved reserves beginning of the year 16,077 16,077 16,077
Revisions of previous estimates (5,395) (5,395) (5,395)
Extensions, discoveries and
improved recovery 12,927 12,927 12,927
Production (3,785) (3,785) (3,785)
Sales of reserves in place (19,818) (19,818) (19,818)
------- ------- -------
Proved reserves end of year 6 6 6
======= ======= =======
YEAR ENDED DECEMBER 31, 1994
Proved reserves beginning of the year 18,099 18,099 18,099
Revisions of previous estimates (1,120) (1,120) (1,120)
Extensions, discoveries and
improved recovery 9,153 9,153 9,153
Production (2,062) (2,062) (2,062)
Sales of reserves in place (7,993) (7,993) (7,993)
------- ------- -------
Proved reserves end of year 16,077 16,077 16,077
======= ======= =======
PROVED DEVELOPED RESERVES AT:
December 31, 1995 6 6 6
December 31, 1994 8,385 8,385 8,385
January 1 , 1994 6,584 6,584 6,584
</TABLE>
S-21
<PAGE> 50
(1) The Securities and Exchange Commission requires the reserve presentation
to be calculated using year-end prices and costs and assuming a
continuation of existing economic conditions. Proved reserves cannot be
measured exactly, and the estimation of reserves involves judgmental
determinations. Reserve estimates must be reviewed and adjusted
periodically to reflect additional information gained from reservoir
performance, new geological and geophysical data and economic changes. The
above estimates are based on current technology and economic conditions,
and the Company considers such estimates to be reasonable and consistent
with current knowledge of the characteristics and extent of production.
The estimates include only those amounts considered to be Proved Reserves
and do not include additional amounts which may result from new
discoveries in the future, or from application of secondary and tertiary
recovery processes where facilities are not in place.
(2) Proved Developed Reserves are reserves which can be expected to be
recovered through existing wells with existing equipment and operating
methods. This classification includes:
(a) Proved developed producing reserves which are reserves expected to be
recovered through existing completion intervals now open for
production in existing wells; and
(b) Proved developed nonproducing reserves which are reserves that exist
behind the casing of existing wells which are expected to be produced
in the predictable future, where the cost of making such oil and gas
available for production should be relatively small compared to the
cost of a new well.
Any reserves expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing primary
recovery methods are included as Proved Developed Reserves only after
testing by a pilot project or after the operation of an installed program
has confirmed through production response that increased recovery will be
achieved.
(3) Proved Undeveloped Reserves are Proved Reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where
a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage are limited to those drilling units offsetting
productive units, which are reasonably certain of production when drilled.
Proved Reserves for other undrilled units are claimed only where it can be
demonstrated with certainty that there is continuity of production from
the existing productive formation. No estimates for Proved Undeveloped
Reserves are attributable to or included in this table for any acreage for
which an application of fluid injection or other improved recovery
technique is contemplated unless proved effective by actual tests in the
area and in the same reservoir.
(4) The Company's engineering estimates indicate that a significant quantity
of natural gas reserves (net to the Company's interest) will be developed
and produced in association with the development and production of the
Company's proved oil reserves in Russia. The Company expects that, due to
current market conditions, it will initially reinject or flare such
associated natural gas production, and accordingly, no future net revenue
has been assigned to these reserves. Under the joint venture agreement,
such reserves are owned by the Company in the same proportion as all other
hydrocarbons in the field, and subsequent changes in conditions could
result in the assignment of value to these reserves.
(5) Changes in previous estimates of proved reserves result from new
information obtained from production history and changes in economic
factors.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVE QUANTITIES (UNAUDITED)
The standardized measure of discounted future net cash flows is presented in
accordance with the provisions of SFAS No. 69. In preparing this data,
assumptions and estimates have been used, and the Company cautions against
viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for
fixed and determinable escalations provided by contract, to the estimated future
production of year-end proved reserves. Future cash inflows were reduced by
estimated future production and development costs to determine pre-tax cash
inflows. Future income taxes were estimated by applying the year-end statutory
tax rates to the future pre-tax cash inflows, less the tax basis of the
properties involved, and adjusted for permanent differences and tax credits and
allowances. The resultant future net cash inflows are discounted using a ten
percent discount rate.
S-22
<PAGE> 51
GEOILBENT received a waiver from the export tariff assessed on all oil produced
in and exported from Russia for 1995. The discounted value of the waiver net to
the Company's interest as of December 31, 1994 was approximately $3 million. In
July 1996, such oil export tariffs were terminated in conjunction with a loan
agreement with the International Monetary Fund. Excise, pipeline and other taxes
continue to be levied on all oil producers and certain exporters. The Russian
regulatory environment continues to be volatile and the Company is unable to
predict the impact of taxes, duties and other burdens for the future. For
purposes of estimating future net cash flows at December 31, 1996, excise duties
of approximately $0.74 per Bbl have been applied to all future production.
STANDARDIZED MEASURE
<TABLE>
<CAPTION>
MINORITY
UNITED INTEREST IN
VENEZUELA RUSSIA STATES TOTAL VENEZUELA NET TOTAL
---------------------------------------------------------------------------
(amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1996
Future cash inflow $1,036,611 $291,951 $1,328,562 $(207,322) $1,121,240
Future production costs (347,498) (94,279) (441,777) 69,500 (372,277)
Other related future costs (65,454) (45,723) (111,177) 13,091 (98,086)
---------- -------- ---------- --------- ----------
Future net revenue before income taxes 623,659 151,949 775,608 (124,731) 650,877
10% annual discount for estimated timing of cash
flows (176,805) (61,244) (238,049) 35,361 (202,688)
---------- -------- ---------- --------- ----------
Discounted future net cash flows before income taxes 446,854 90,705 537,559 (89,370) 448,189
Future income taxes, discounted at 10% per annum (123,304) (17,282) (140,586) 24,661 (115,925)
---------- -------- ---------- --------- ----------
Standardized measure of discounted future net
cash flows $323,550 $73,423 $396,973 $ (64,709) $332,264
========== ======== ========== ========= ==========
DECEMBER 31, 1995
Future cash inflow $652,110 $283,630 $ 19 $ 935,759 $(130,422) $ 805,337
Future production costs (170,328) (102,783) (2) (273,113) 34,066 (239,047)
Other related future costs (76,368) (36,686) 0 (113,054) 15,274 (97,780)
---------- -------- ---------- ---------- --------- ----------
Future net revenue before income taxes 405,414 144,161 17 549,592 (81,082) 468,510
10% annual discount for estimated timing of cash
flows (118,498) (58,800) (1) (177,299) 23,700 (153,599)
---------- -------- ---------- ---------- --------- ----------
Discounted future net cash flows before income taxes 286,916 85,361 16 372,293 (57,382) 314,911
Future income taxes, discounted at 10% per annum (80,371) (29,927) 0 (110,298) 16,074 (94,224)
---------- -------- ---------- ---------- --------- ----------
Standardized measure of discounted future net
cash flows $206,545 $ 55,434 $ 16 $ 261,995 $ (41,308) $ 220,687
========== ======== ========== ========== ========= ==========
DECEMBER 31,1994
Future cash inflow $528,214 $204,520 $32,091 $ 764,825 $(105,643) $ 659,182
Future production costs (64,950) (98,767) (3,760) (167,477) 12,990 (154,487)
Other related future costs (79,486) (25,378) (2,002) (106,866) 15,897 (90,969)
---------- -------- ---------- ---------- --------- ----------
Future net revenue before income taxes 383,778 80,375 26,329 490,482 (76,756) 413,726
10% annual discount for estimated timing of cash
flows (114,948) (31,542) (7,672) (154,162) 22,990 (131,172)
---------- -------- ---------- ---------- --------- ----------
Discounted future net cash flows before income taxes 268,830 48,833 18,657 336,320 (53,766) 282,554
Future income taxes, discounted at 10% per annum (96,127) (16,435) (371) (112,933) 19,225 (93,708)
---------- -------- ---------- ---------- --------- ----------
Standardized measure of discounted future net
cash flows $172,703 $ 32,398 $18,286 $ 223,387 $ (34,541) $ 188,846
========== ======== ========== ========== ========= ==========
</TABLE>
S-23
<PAGE> 52
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------
CHANGES IN STANDARDIZED MEASURE 1996 1995 1994
---- ---- ----
(amounts in thousands)
<S> <C> <C> <C>
Balance, January 1 $261,995 $223,387 $102,516
Changes resulting from:
Sales of oil and gas, net of related costs (121,954) (52,170) (22,741)
Revisions to estimates of proved reserves:
Pricing 108,705 (6,990) (6,243)
Quantities (56,315) (63,802) (4,150)
Sales of reserves in place (18) (28,102) (28,664)
Extensions, discoveries and improved recovery,
net of future costs 183,968 170,037 169,860
Purchases of reserves in place 72,206
Accretion of discount 37,230 33,632 13,142
Change in income taxes (30,288) 2,635 (84,036)
Development costs incurred 63,013 47,657 13,365
Changes in timing and other (49,363) (64,289) (1,868)
-------- -------- --------
Balance, December 31 $396,973 $261,995 $223,387
======== ======== ========
</TABLE>
NOTE 16 - QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 (a)
-------- ------- ------------ ---------------
(amounts in thousands, except per share data)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1996
Revenues $32,939 $41,890 $40,901 $49,336
Expenses 19,853 20,935 22,809 32,620
------- ------- ------- -------
Income before incomes taxes and minority interest 13,086 20,955 18,092 16,716
Income taxes 4,449 4,992 6,401 4,666
------- ------- ------- -------
8,637 15,963 11,691 12,050
Minority interest 2,327 2,073 2,878 2,706
------- ------- ------- -------
Income before extraordinary charge 6,310 13,890 8,813 9,344
Extraordinary charge for early retirement of debt,
net of tax benefit 10,075
------- ------- ------- -------
Net income $ 6,310 $ 3,815 $ 8,813 $ 9,344
======= ======= ======= =======
Income per common share:
Primary:
Income before extraordinary charge $ 0.23 $ 0.47 $0.29 $ 0.30
Extraordinary charge (0.34)
------- ------- ------- -------
Net income $ 0.23 $ 0.13 $ 0.29 $ 0.30
======= ======= ======= =======
Fully diluted:
Income before extraordinary charge $ 0.22 $ 0.46 $ 0.29 $ 0.30
Extraordinary charge (0.33)
------- ------- ------- -------
Net income $ 0.22 $ 0.13 $ 0.29 $ 0.30
======= ======= ======= =======
</TABLE>
S-24
<PAGE> 53
<TABLE>
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1995
Revenues $12,661 $13,209 $18,290 $20,908
Expenses 8,678 10,327 12,735 14,955
------- ------- ------- -------
Income before incomes taxes and minority interest 3,983 2,882 5,555 5,953
Income taxes 1,079 892 1,308 (801)
------- ------- ------- -------
Income before minority interest 2,904 1,990 4,247 6,754
Minority interest 863 880 1,343 2,218
------- ------- ------- -------
Net income $ 2,041 $ 1,110 $ 2,904 $ 4,536
======= ======= ======= =======
Net income per common share:
Primary $ 0.08 $ 0.04 $ 0.11 $ 0.17
======= ======= ======= =======
Fully diluted $ 0.08 $ 0.04 $ 0.11 $ 0.16
======= ======= ======= =======
<FN>
(a) The quarter ended December 31, 1995 does not include revenues and expenses related to GEOILBENT (see Note 15).
</TABLE>
S-25
<PAGE> 54
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of
Carpinteria, State of California, on the 26th day of March, 1997.
BENTON OIL AND GAS COMPANY
--------------------------
(Registrant)
Date: March 26, 1997 By: /s/A.E. Benton
------------------------ ------------------------------
A.E. Benton
Chief Executive Officer and
Principal Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed by the following persons on the 26th day of March,
1997, on behalf of the Registrant in the capacities indicated:
<TABLE>
<CAPTION>
Signature Title
- --------- -----
<S> <C>
/s/A. E. Benton Chairman, Chief Executive Officer and
- --------------------------------------------- Director
A. E. Benton
(Principal Executive Officer)
/s/Michael B. Wray President, Chief Financial Officer and
- --------------------------------------------- Director
Michael B. Wray
(Principal Financial Officer)
/s/Chris C. Hickok Vice President - Controller
- ---------------------------------------------
Chris C. Hickok
(Principal Accounting Officer)
/s/Bruce M. McIntyre Director
- ---------------------------------------------
Bruce M. McIntyre
/s/Richard W. Fetzner Director
- ---------------------------------------------
Richard W. Fetzner
/s/Garrett A. Garrettson Director
- ---------------------------------------------
Garrett A. Garrettson
</TABLE>
<PAGE> 55
EXHIBITS
<PAGE> 1
EXHIBIT 11.1
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
COMPUTATION OF EARNINGS PER COMMON SHARE
----------------------------------------
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1995 1994
------------ ----------- -----------
<S> <C> <C> <C>
PRIMARY EARNINGS PER SHARE
- --------------------------
Net income (loss) attributable to common stock $ 28,282,010 $10,591,035 $ 2,954,161
Weighted average number of common shares outstanding 27,088,308 25,083,570 24,850,922
============ =========== ===========
Primary earnings (loss) per share $ 1.04 $ 0.42 $ 0.12
============ =========== ===========
ADDITIONAL PRIMARY COMPUTATION
- ------------------------------
Net income (loss) attributable to common stock $ 28,282,010 $10,591,035 $ 2,954,161
Shares
Weighted average number of common shares outstanding 27,088,308 25,083,570 24,850,922
Add shares assuming exercise of options reduced by the number
of shares which could have been purchased with the
proceeds from exercise of such options 2,502,051 1,589,913 463,104
------------ ----------- -----------
Primary weighted average number of common shares outstanding
as adjusted 29,590,359 26,673,483 25,314,026
============ =========== ===========
Primary earnings (loss) per share $ 0.96 $ 0.40 $ 0.12
============ =========== ===========
ASSUMING FULL DILUTION
- ----------------------
Net income (loss) attributable to common stock $ 28,282,010 $10,591,035 $ 2,954,161
Shares
Weighted average number of common shares outstanding 27,088,308 25,083,570 24,850,922
Add shares assuming exercise of options reduced by the number
of shares which could have been purchased with the
proceeds from exercise of such options 3,105,125 2,205,773 565,870
------------ ----------- -----------
Weighted average number of common shares outstanding as
adjusted 30,193,433 27,289,343 25,416,792
============ =========== ===========
Earnings (loss) per common share assuming full dilution $ 0.94 $ 0.39 $ 0.12
============ =========== ===========
ADDITIONAL FULLY DILUTED COMPUTATION
Additional adjustment to net income (loss) as adjusted per
fully diluted computation above:
Net income (loss) as adjusted per fully diluted computation
above $ 28,282,010 $10,591,035 $ 2,954,161
Add after tax interest expense attributable to convertible notes (70,880) 345,520 372,960
Add after tax interest expense attributable to convertible
debentures 103,574 455,279 514,240
------------ ----------- -----------
Net income (loss) as adjusted $ 28,314,704 $11,391,834 $ 3,841,361
------------ ----------- -----------
Additional adjustment to weighted average number of
shares outstanding:
Weighted average number of common shares outstanding 27,088,308 25,083,570 24,850,922
Add shares assuming conversion of convertible debentures 200,086 585,295 650,237
Add shares assuming conversion of convertible notes 21,174 388,324 397,477
Add shares assuming exercise of options reduced by the number
of shares which could have been purchased with the
proceeds from exercise of such options 3,105,125 2,205,773 565,870
------------ ----------- -----------
Weighted average number of common shares outstanding as
adjusted 30,414,693 28,262,962 26,464,506
============ =========== ===========
Earnings (loss) per common share assuming full dilution $ 0.93 $ 0.40 $ 0.15
============ =========== ===========
</TABLE>
<PAGE> 1
EXHIBIT 21.1
BENTON OIL AND GAS COMPANY
LIST OF SUBSIDIARIES
<TABLE>
<CAPTION>
JURISDICTION
NAME OF INCORPORATION
------------------------------------------------------------- ----------------
<S> <C>
Benton-Vinccler, C.A.* Venezuela
Energy International Financial Institution, Ltd.* Cayman Islands
Crestone Energy Corporation Colorado
CEC Holding Company Delaware
<FN>
*All subsidiaries are wholly-owned by Benton Oil and Gas Company, except
Benton-Vinccler, C.A. which, effective March 4, 1994, is owned 80% by Benton
Oil and Gas Company and Energy International Financial Institution which is
owned 80% by Benton Oil and Gas Company.
</TABLE>
<PAGE> 1
EXHIBIT 23.1
BENTON OIL AND GAS COMPANY
INDEPENDENT AUDITORS' CONSENT
-----------------------------
We consent to the incorporation by reference in Registration Statement Nos.
33-37124 on Form S-8, 33-70146 on Form S-3, 33-77946 on Form S-3, 333-135 on
Form S-3, 333-17231 on Form S-3 and 333-19679 on Form S-8 of Benton Oil and Gas
Company of our report dated March 20, 1997 appearing in this Annual Report on
Form 10-K of Benton Oil and Gas Company for the year ended December 31, 1996.
Deloitte & Touche LLP
Los Angeles, California
March 26, 1997
<PAGE> 1
EXHIBIT 23.2
BENTON OIL AND GAS COMPANY
INDEPENDENT PETROLEUM ENGINEERS' CONSENT
Huddleston & Co., Inc., hereby consents to the use of its name in reference to
it regarding its audit of the Benton Oil and Gas Company reserve reports, dated
as of December 31, 1996, in the Form 10-K Annual Report of Benton Oil and Gas
Company to be filed with the Securities and Exchange Commission.
Peter D. Huddleston, P.E.
Huddleston & Co., Inc.
Houston, Texas
March 26, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K
FOR THE PERIOD ENDED DECEMBER 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<EXCHANGE-RATE> 1
<CASH> 32,431,709
<SECURITIES> 52,003,995
<RECEIVABLES> 59,997,492
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 150,524,684
<PP&E> 263,904,855
<DEPRECIATION> 52,870,176
<TOTAL-ASSETS> 435,745,241
<CURRENT-LIABILITIES> 52,107,380
<BONDS> 175,028,205
0
0
<COMMON> 288,983
<OTHER-SE> 174,610,213
<TOTAL-LIABILITY-AND-EQUITY> 435,745,241
<SALES> 147,703,421
<TOTAL-REVENUES> 167,066,498
<CGS> 59,042,976
<TOTAL-COSTS> 59,042,976
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 16,128,442
<INCOME-PRETAX> 68,849,489
<INCOME-TAX> 20,508,623
<INCOME-CONTINUING> 38,356,809
<DISCONTINUED> 0
<EXTRAORDINARY> 10,074,799
<CHANGES> 0
<NET-INCOME> 28,282,010
<EPS-PRIMARY> 0.96
<EPS-DILUTED> 0.93
</TABLE>
